New York State has initiated an historic restructuring of the way New
Yorkers will purchase electricity. While part of a national trend, the
New York initiative is in the vanguard. The New York experience will undoubtedly
set precedents and provide lessons applicable in other jurisdictions, nationally
and perhaps internationally. This Report is on the status, as of April
1998, of New York State's restructuring effort, which will introduce retail
competition and choice of supplier for the New York electricity consumer.
While many of the details remain nascent and in some respects untested,
a brief review of the emerging structure may be useful to residential,
commercial and industrial consumers of electricity, to participants in
the electric utility industry, to investors, to their advisors and -- because
the process necessarily involves a complex of political issues -- to voters
and legislators.

This Report is in three parts. First, in Part I, the institutional and
legal structure of the electric utility industry is sketched broadly. Several
of the forces contributing to the restructuring initiative are also set
forth in Part I together with a discussion of the process of change in
New York. Second, in Part II, the restructuring plans of the seven investor-owned
electric utility companies are summarized. Generally, these plans reflect
collaborative efforts among a number of interested parties to reach agreement
on a restructuring plan for each company. Each plan has been approved by
the New York Public Service Commission ("PSC"). Finally, in Part
III, several issues and questions about the future of the restructuring
effort in New York are posed. A glossary of pertinent terms used in this
Report is set forth in the Appendix.

PART I

BACKGROUND

The Traditional Structure Of The Industry

Overview

Historically, the dominant characteristics of the electric utility industry
have been vertical integration and monopoly, with utility operations generally
limited to a single state or locality. The reasons have been historical,
technological and economic.
Industry pioneers at the end of the nineteenth century who wished to offer
electric service to the public had no suppliers to buy from and hence had
to generate their own supply. Also, since continuity and reliability of
supply were essential to attracting customers for this new commodity, and
since there was no practical way to store electricity, it was necessary
for the distributors of electricity to have at their command a system of
generators designed and operated so as to have the capacity to supply,
from moment to moment, just the right amount of electricity to meet the
demand of the distribution system's customers as that demand fluctuated
over the day, the week and the year. Limitations on early transmission
technology tended to restrict utility systems to a single locality. As
transmission technology developed, the transmission lines were built by
the owner of the local generation/distribution system, to link different
parts of the system, to link remote generation facilities to the distribution
system, and eventually to establish links with neighboring systems. As
these links developed, the vertically integrated generation/transmission/distribution
systems found that interconnection permitted them to share reserve capacity,
take advantage of load diversity and increase system reliability.

The capital-intensive nature of the business, the need to achieve economies
of scale, the need to use public ways to locate distribution lines, the
diseconomies (and environmental negatives) of multiple, redundant and competing
lines and facilities, and public safety concerns led to legal recognition
of a "natural monopoly" system under which a single vertically
integrated electric utility would be designated as the sole supplier of
electricity to the public within a franchised service area.
Over time, a regulatory framework developed, part statutory and part common
law, under which electric utilities gained a franchise monopoly and eminent
domain powers, and became responsible for providing safe and reliable electric
service on a non-discriminatory basis to all members of the public requesting
service within the franchise area, at regulated rates set by a government
body (in New York State, the PSC). As part of its duty to serve, the electric
utility would be obligated to implement social and environmental programs
and policies set by the PSC, the legislature, or other government bodies
having jurisdiction (e.g., pollution reduction, energy efficiency, low
income programs and economic development rates). Some of these social/environmental
programs and policies might have been uneconomic in a competitive market.
For example, an unregulated competitive market participant might decline
to provide service to a particular customer or class of customers, or to
provide a particular service, if the business was deemed unattractive or
not sufficiently profitable to justify the investment and risk involved
in adding the capacity necessary to provide the service. The regulated
utility would nevertheless be required to provide service, if so mandated.
The regulated rates set by the PSC were designed to take this burden into
account by providing a reasonable prospect of receiving sufficient revenues
to recover all expenses reasonably incurred, and all investments reasonably
made, for the purpose of providing mandated service, together with a reasonable
return on such investments (the "prudent investment" standard).

Federal Legislation

Utility regulation has for the most part been a local matter left to
the several states. However, three federal statutes have significantly
affected the development of the electric utility industry in this country.

Public Utility Holding Company Act of 1935 ("PUHCA")

PUHCA was enacted in 1935 in reaction to financing abuses and securities
fraud involved in the organization and eventual spectacular collapse of
an over-leveraged pyramid of holding companies in the electric and gas
utility industries. The reforms introduced in these industries by PUHCA
have been largely subsumed by the subsequent development of the federal
securities laws, which were enacted contemporaneously with PUHCA. The Securities
and Exchange Commission, which administers most of the provisions of PUHCA,
has recommended that it be repealed. Nevertheless, PUHCA remains, and has
strongly influenced the organizational structure of the electric utility
industry. PUHCA's principal feature is the imposition of a comprehensive
and burdensome overlay of federal regulation on any "holding company"
(defined as the owner of 10 per cent or more of the voting stock of an
electric or gas utility company), and on the subsidiaries of such holding
company, unless an exemption from PUHCA is available. The effect of this
has been to impose on the electric utility industry a strong bias toward
local, rather than regional or national, organization. PUHCA exemptions
are generally unavailable to holding company systems with multi-state utility
operations, and state law considerations generally require, as a practical
matter, that utility companies be domestic corporations. While a few multistate
utility holding company systems do exist and serve a significant portion
of the country while operating under the PUHCA regulatory regime, the more
general rule has been that where consolidation has occurred, it has been
confined to a single state. Facility structures tend to follow organizational
structures. Thus, no national electric transmission companies exist in
this country, although we have built several national telephone systems.

Part II of the Federal Power Act ("FPA")

Substantial interstate transmission and sales of electricity developed
at the wholesale level among the various, mostly local, electric utility
companies. Part II of the FPA was enacted in 1935 to establish federal
regulation of this interstate commerce in electricity. The jurisdiction
of the Federal Energy Regulatory Commission ("FERC"), which administers
the FPA, extends to wholesale sales and transmission of electricity in
interstate commerce. The uniformity of federal regulation of transmission
facilities has helped to enable the disparate transmission facilities across
the country to function as if they were parts of an integrated system,
even though each element was designed and built to serve the separate interests
of the local utility owning the facility.

Public Utility Regulatory Policies Act of 1978 ("PURPA")

The oil crisis of the early 1970s brought about a drastic increase in
energy prices, including the price of electricity. This in turn focused
national attention on energy conservation, energy efficiency and alternatives
to oil as a source of energy. One of the outcomes was the enactment of
PURPA. Among other things, PURPA defined a new class of non-traditional
electric generating facilities that would either (i) produce electricity
with greater energy efficiency through "cogeneration" (a process
or system utilizing waste heat from electric generation for a second purpose,
such as using exhaust steam for space heating or process heat), or (ii)
produce electricity from "alternative" energy sources, such as
small hydro, wind, solar, biomass and geothermal sources. These new facilities
could not be owned primarily by traditional utilities, but by independent
operators. These independent power producers ("IPPs"), if they
satisfied the PURPA requirements, would be entitled to exemption from normal
utility regulation and would be entitled to require a traditional utility
to purchase electricity from the IPPs at the utility's "avoided cost."
Initially, the electric commerce regulated under the FPA was almost exclusively
a commerce among traditional electric utilities, as they provided transmission
services to each other over their respective transmission lines, to facilitate
wholesale purchases and sales of electric capacity and energy among themselves,
and transactions with the entities discussed below under the heading, "Public
Power." This exclusivity ended with the enactment of PURPA. While
many of the resulting power purchase agreements were with the local franchise
utility, some agreements were with utilities more distant.
Enactment of PURPA at the federal level was followed in some states, including
New York, by "little PURPA" state legislation offering further
encouragement to the development of IPPs. The New York version included
a provision -- since repealed prospectively -- that required the utility
to pay a qualifying IPP the greater of the utility's avoided cost or 6
cents per KWH. The legislation had the effect of mandating utilities to
enter into long-term purchase contracts based on assumed future oil prices
which proved to be lower than anticipated.
The economic incentives created by PURPA and the companion New York legislation
had a dramatic effect. Numerous and large generating facilities were built
by entrepreneurs attracted by assured revenue streams. The new cogeneration
facilities incorporated the latest technology, often enabling the new facilities
to produce electricity at substantially lower cost than the older machines
of the traditional utilities.
PURPA also established a number of rate making standards, including standards
addressing efficiency, conservation and rate payer protection. State regulatory
authorities are required by PURPA to consider the standards set forth in
PURPA and to determine whether it is appropriate to implement such standards.
The pace of changing operating and regulatory patterns, which had begun
in the 1980s after the enactment of PURPA in 1978, accelerated with the
enactment of the Energy Policy Act of 1992 and FERC's issuance of its Order
888 in 1996. Under Order 888, FERC mandated that transmission facility
owners operate their system on an "open access" basis. Under
the FERC's open access policy, the owners of all jurisdictional transmission
facilities -- effectively all transmission facilities -- are required to
make the use of their transmission facilities available under FERC-approved
non-discriminatory tariff rates and terms. The FERC open access policy
set the stage for electric utility restructuring.

Public Power

In parallel with the development of investor-owned utilities as outlined
above, public entities have developed to serve a xdportion of the U.S.
electricity market, including a portion of the New York market. In a relatively
small but nevertheless significant number of communities in New York and
elsewhere, the local electric distribution system is owned and operated
by the local government or a government agency. These municipal systems
typically do not own or operate a generating system, but purchase their
electric supply from an outside source or sources. Typically, but not necessarily,
these outside sources are also government entities. The Tennessee Valley
Authority and the Bonneville Power Administration are two well-known electricity
suppliers at the federal level. In New York State there is the New York
Power Authority ("NYPA"). Created by the New York State Legislature
(the "Legislature") in 1931, NYPA developed the large St. Lawrence
and Niagara hydro sites in the 1950s and 1960s and today operates these
generating facilities along with a portfolio of nuclear, fossil and other
hydro generating facilities and a system of major transmission lines linking
various parts of the State with each other and with Ontario Hydro and Hydro-Quebec,
two Canadian entities which export significant amounts of electricity to
New York and other U.S. markets. NYPA sells electricity to investor-owned
utilities, other public agencies within and without New York State and
industrial customers, as well as to New York municipal systems.
In 1986, the Legislature created a second public authority, the Long Island
Power Authority ("LIPA"), to resolve the controversy over the
Shoreham Nuclear Power Plant ("Shoreham"). LIPA acquired title
to Shoreham in 1992 and, pursuant to an agreement with the Long Island
Lighting Company ("LILCO"), decommissioned Shoreham. In June
1997, LIPA agreed to acquire LILCO's securities or assets after LILCO has
transferred its Long Island generation and gas system to subsidiaries of
a new LILCO/The Brooklyn Union Gas Company holding company.
NYPA, LIPA and the New York municipal systems are mentioned here only to
complete the picture of the existing electric industry in New York; they
are not directly addressed by the current restructuring initiative that
is the subject of this Report.

The Drivers Of Change

The restructuring of the electric utility industry is fundamentally
changing an essential component of society's infrastructure. It is natural
to ask why, and why now. The restructuring initiative is a response to
three converging forces: progress in technology; economics; and the example
of deregulation and increased competition in other regulated industries,
notably the natural gas industry.

Progress in Technology

Many of the generating facilities in use by the traditional regulated
utilities are decades old and incorporate technologies which would not
be used in a generating plant being built today. Combined cycle gas fueled
plants, for example, have been developed over the past 15 to 20 years.
These plants provide high reliability, lower cost and reduced environmental
impact because of the more efficient use of natural gas. Nevertheless,
many of the older plants remain in service because a substantial part of
their cost has not yet been amortized, i.e., recovered, under the cost-based
rates of traditional regulation. The burden of proving that the investment
in the new plant is a prudent (and hence recoverable) one, is on the utility.
The issue is further clouded by the fact that in a cost-of-service-based
pricing system, the output cost of the existing plant serves as a proxy
for the market in determining the reasonable, or "right" price.
Competition, and elimination of price regulation, in generation has encouraged
the implementation of new technology and will provide a market test to
determine the optimal time for replacement of old facilities.

The technology of long-distance power transmission continues to advance,
making it feasible for a low-cost generator to sell its output in an ever
wider area, and for a market to seek ever more distant low-cost suppliers
of electricity. This increase in the number of potential market participants
enhances the advantage of competitive electric pricing over regulated pricing.

The electric utility industry was among the first to recognize the potential
of the computer and information technology. Continued and intensive implementation
of this technology has created the necessary infrastructure for a true
auction market in electricity. The same technology applied to capacity
management makes it feasible to explore substituting a "virtual"
generating system, constructed of shifting contractual commitments, for
a dedicated system of physical generating plants.

Economics

A principal impetus for the restructuring initiative is the condition
of the New York State economy. Despite a relatively healthy national economy
and a booming financial sector which has benefited the downstate region,
New York's economy has lagged, particularly in the creation and retention
of new business and jobs. A perceived factor in this lag is the high cost
of electricity in New York State, relative to the national average, together
with other factors, such as high taxes and heavy regulation of business.
The restructuring initiative and the introduction of retail competition
are seen as necessary steps to bring down the cost of electricity in New
York and thereby restore New York's competitiveness.

The effects of past regulatory policies have contributed to the current
pressures for restructuring. New York utilities entered into long-term
contracts mandated under PURPA and New York's companion legislation which
require the utilities to purchase substantial amounts of electric capacity
and energy from IPPs at prices that are now substantially higher than the
wholesale market. The resulting growth of IPP capacity has led to excess
generating capacity in New York and elsewhere, forcing prices down in the
wholesale electric market.

Another argument for changing the present system is the perceived disparity
between the "regulated" and the "unregulated" prices
of electricity in New York. The perceived disparity is great. It is important,
however, to distinguish between perception and reality. While state-of-the-art
unregulated generators are often able to produce energy at lower cost than
older plants, this disparity is not the one which looms large for the consumer.
Rather, it is the five-fold (or greater) differential between the wholesale
price of electricity and the "regulated" (i.e., retail) price.

The regulated, retail price includes not only pure generation costs, but
also other costs such as delivery and administrative costs, reliability
and load factor costs, incremental costs of local generation imposed by
transmission constraints, rate structure cross subsidies, recovery of prior
investments determined by the PSC to be prudent, the costs of mandated
social/environmental programs, and of course taxes. It is no secret that
New York has cast the regulated utility in the unwelcome role of a major
tax collector. All of this said, the differential was substantial and growing,
as was popular demand for change by a public impatient with explanations
for bills that, rightly or wrongly, were perceived as too high.

The development, in recent years, of a vigorous competitive wholesale market
for electricity has suggested that a similarly competitive market could
be developed at the retail level. The emergence of numerous independent
"energy marketers" acting as intermediaries between wholesale
sellers and retail customers has strengthened this belief. In a competitive
retail market it is reasonable to expect that lowered wholesale prices
will translate into lower retail prices.

The Example of Other Regulated Industries

Recent years have seen the introduction, at both national and state
levels, of major regulatory restructuring and increased competition in
the traditionally regulated telephone and natural gas industries.
The telephone industry has seen sweeping regulatory and statutory changes
in the last two decades, with the introduction of competition and increasingly
wider choices of service providers. From the perspective of the average
consumer, the experiment has been a clear success in terms of lower long-distance
rates, with mixed reviews for the cost and quality of local service.

The natural gas industry is seen as a particularly close parallel to the
current electric initiative, since most New Yorkers purchase gas and electric
service from the same utility. Retail gas customers of New York utilities
now have the option to purchase their gas from suppliers other than their
local gas utility. Such customers have their gas delivered by their supplier
of choice to the local gas utility's "city gate" (the point of
interconnection between the local gas utility's system of pipes and the
interstate pipeline through which the supplier ships the gas). The gas
is fungible and the local gas utility delivers a like quantity to the customer,
charging the customer a transportation-only charge. The transportation-only
charge amounts to the local gas utility's normal "full service"
rate, minus the utility's normal charge for the gas commodity itself. Large
gas customers have the option to purchase their gas directly at the well-head
and arrange for their own pipeline transportation to the city gate. Most
customers, and all small customers, choosing transportation-only service
from their local gas utility will purchase their gas from an independent
"gas marketer" who will assume responsibility for procurement
and delivery to the city gate. Competition among gas marketers is vigorous
and the transportation-only option from the local utility offers the gas
consumer an opportunity -- but not necessarily an assurance -- of savings
compared to traditional gas service. While the transportation-only option
is fairly new, except for very large customers, and market penetration
remains low, particularly for residential customers, no insuperable problems
have surfaced to date.

The relatively smooth introduction of retail competition in the natural
gas industry has provided both a model and an arguably practical demonstration
of feasibility for a similar transition in the electric utility industry.
Critics have questioned the applicability of the model, noting differences
in the physical nature of the two commodities, the markets, the applicable
statutes, the industry structures, and the lack of significant experience
with large numbers of small customers in the gas retail competition initiative.
In any event, the PSC has elected to proceed with retail electric choice.

The Special Case of Shoreham

A final element among the drivers of change in New York is the "Shoreham
Problem." Shoreham was a nuclear generating plant constructed on Eastern
Long Island by LILCO over determined and protracted opposition. After many
years of costly controversy and delay, the plant was finally completed
in the late 1980s. However, the plant was not allowed to go into service,
and was retired and dismantled, under an agreement negotiated with the
intervention of the New York State government. The arrangement contemplated
the recovery by LILCO of most of its prudent investment in Shoreham and
related costs  a figure ultimately exceeding $5 billion  through LILCO's
electric rates over a long period of time. Despite the lengthy recovery
period, LILCO's electric rates soon rose to become among the highest in
the nation. Repudiation of the opportunity to recover the Shoreham costs
would have been an immediate threat to the solvency of LILCO, but the public
outcry over electric rates on Long Island made it clear that something
had to be done about the "Shoreham Problem."

The Process Of Change In New York

The transition process in New York State has thus far been entirely
an administrative one. The transition plan for each New York electric utility
has been hammered out between the utility and the PSC in the context of
existing statutory provisions, although not without challenge. Legislation
enacted to date has been directed to a reduction of the utility gross receipts
tax, which has helped to achieve a portion of the rate reductions sought
by the PSC. Some individual utility plans do contemplate the possibility
of further reductions in the gross receipts tax, and of legislation authorizing
securitization of certain utility revenue streams.

In 1993, the PSC on its own motion began a proceeding to examine various
issues relating to potential competition in the regulated gas and electric
industries in New York State. (Order Instituting Proceeding, March 19,
1993, Case 93-M-0229.) In 1994, the PSC instituted Phase II of the proceeding,
focusing on competition in the electric utility industry (Order Instituting
Phase II, August 9, 1994, Case 93-M-0229.) The proceeding was redesignated
Case 94-E-0952, reflecting its electric focus, by order issued November
30, 1994. This proceeding culminated in an opinion and order issued May
20, 1996, stating a "vision" for the New York electric utility
industry. (Opinion No. 96-12, May 20, 1996, Case 94-E-0952) (hereinafter
"Opinion No. 96-12"). The "vision" included the following
elements: (1) introduction of effective competition in generation; (2)
electric rate reductions; (3) customer choice of energy supplier; (4) retention
of a "provider of last resort" requirement; (5) retention of
a funding mechanism for social/environmental programs; and (6) creation
of an independent (transmission) system operator ("ISO") to ensure
reliability.
Opinion No. 96-12 directed each of the five New York electric utilities
other than Niagara Mohawk Power Corporation ("Niagara Mohawk")
and LILCO to file with the PSC by October 1, 1996 the utility's plan for
implementing the PSC's "vision" and addressing: (1) a schedule
for the introduction of retail access; (2) a rate reduction plan; and (3)
changes in the utility's corporate structure to accommodate the "vision".
Niagara Mohawk was exempted from the October 1, 1996 filing requirement
because it had already filed a retail access and restructuring plan with
the PSC.

LILCO was exempted because it was engaged in negotiating the restructuring
transactions with The Brooklyn Union Gas Company ("Brooklyn Union")
and LIPA. As detailed below in Part II, LILCO and Brooklyn Union have agreed
to combine their companies. The new combined entity will use a holding
company form of organization. Contemporaneously, LILCO and LIPA agreed
that LILCO would transfer its transmission and distribution system to LIPA,
along with other assets and the responsibility of providing electric service
to LILCO's customers.

Each of the five utilities which were not exempted made the filing required
by Opinion No. 96-12. Concurrently, they and other persons initiated litigation
challenging certain aspects of Opinion No. 96-12, including challenging
the PSC's power to restructure the electric utility industry without statutory
changes. While this effort was unsuccessful in the trial court, appeals
were taken. Subsequent to these filings and after protracted negotiations
with the staff of the PSC, namely the New York Department of Public Service
Staff ("DPS Staff") and other interested parties, each of the
five utilities entered into a settlement agreement with the DPS Staff and
other parties, which was subsequently approved by the PSC. A similar settlement
was executed by Niagara Mohawk and the DPS Staff and approved by the PSC.
The negotiation/approval process was completed for all six settlement agreements,
which are summarized in Part II of this Report, by February 1998. As part
of these settlements, the litigation challenging the validity of Opinion
No. 96-12 was conditionally terminated by the utilities, but not by the
other parties.

A significant issue in the restructuring proceeding was the maintenance
of environmental protection. In Opinion No. 96-12, the PSC directed that
a "non-bypassable system benefits charge" ("SBC") be
established for each affected utility at the level of "current utility
expenditures" to support investments in energy efficiency, research,
development and demonstration, low-income programs and environmental monitoring
that might not be expected to take place in a competitive market. Under
Opinion No. 96-12, the SBC is intended to mitigate certain adverse environmental
impacts of utility restructuring identified in the generic environmental
impact statement prepared by the PSC. Statewide, about $233 million in
SBC funds will be collected through wires charges by the six utilities
over the next three years, at a rate of $78 million per year, or about
0.75 mills (0.75 of a tenth of a cent) per KWH. In January, 1998 the PSC
designated the New York State Energy Research and Development Authority
("NYSERDA") to be the statewide administrator for the SBC program.
The six utilities will continue to administer some existing programs. Legislation
has been introduced in both chambers of the Legislature to increase SBC
levels to 4 mills per KWH.
In August 1997, the DPS Staff issued a report calling for the utilities
subject to PSC jurisdiction to divest their four nuclear power plants.
The PSC instituted an administrative proceeding, Case 98-E-0405, on March
20, 1998 to address the issues raised in the DPS Staff report. That proceeding
is pending.

PART II

THE RESTRUCTURING PLANS

The seven utilities' restructuring plans are comparable in some respects,
but each has certain distinct features. Each restructuring plan, reflecting
the agreement of a number of interested parties and then approved by the
PSC, is summarized in the paragraphs of this Part of the Report.

Most, but not all, of the plans call for scheduled reductions in electricity
prices paid by all classes of customers, whether or not such customers
choose to purchase their electricity from an alternative supplier. Most,
but not all, of the plans call for disposition by the utility of all or
substantially all, of the utility's non-nuclear generating facilities.
All of the plans contemplate that by the end of the period (three to five
years) covered by the plan, all customers of the utility will have the
ability to purchase their electricity from an alternative supplier, although
the traditional utility will continue to deliver the electricity to the
consumer, regardless of its source. All of the plans are premised on the
expectation that a competitive market for the supply of electricity will
result in lower electricity prices for all classes of customers.

Consolidated Edison Company Of New York, Inc.

On September 23, 1997, the PSC issued a one-commissioner order in Case
96-E-0897, approving the Amended and Restated Agreement and Settlement
dated September 19, 1997 (the "Con Edison Settlement Agreement")
among Consolidated Edison Company of New York, Inc. ("Con Edison"),
the DPS Staff and various other signatories. The Con Edison Settlement
Agreement sets forth a comprehensive rate, restructuring and competitive
access plan for Con Edison and its electric customers. The September 23
order adopted the terms of the Con Edison Settlement Agreement, subject
to conditions and understandings set forth in the order, and incorporated
them as part of the order. The September 23 order was confirmed by the
order of the full PSC, issued October 1, 1997 in the same case. The bases
for the PSC's approval are set forth in the related Opinion No. 97-16 issued
by the PSC on November 3, 1997 in the same case. Opinion No. 97-16 is currently
the subject of litigation in the New York Supreme Court.

Rate Plan

Duration

The plan covers Con Edison's electric rates for the five years ending
March 31, 2002. The plan "freezes" the base rates (subject to
limited exceptions) at the levels in effect at March 31, 1997, and provides
for reductions from these levels over the five years. The rate freeze had
the immediate effect of eliminating an electric rate increase that would
otherwise have gone into effect on April 1, 1997 pursuant to a 1995 electric
rate settlement approved by the PSC. The scheduled reductions for the first
year of the five-year plan became effective January 1, 1998.

Scheduled reductions (to base rates)

Certain large industrial customers received, as of January 1, 1998,
a 25 per cent electric rate reduction which will continue at that level
throughout the remainder of the five-year period. All other customers will
receive rate reductions beginning at 2 per cent and progressively increasing
to 10 per cent by the beginning of the fifth year of the plan. The decrease
for residential customers will be back-loaded, with 4.5 per cent of the
total 10 per cent decrease occurring in the fifth year of the plan.
The scheduled electric rate reductions include the effects of a reduction,
enacted in 1997, in the New York State utility gross receipts tax. The
tax reduction, like the tax, flows through to the customer. The scheduled
electric rate reductions equate to a cumulative revenue reduction of approximately
$1.2 billion over the five-year period, including the effects of the tax
reduction, or approximately $1 billion excluding such effects. Neither
amount includes the forgone revenues (estimated at $436 million) that would
have resulted from the April 1, 1997 electric rate increase eliminated
by the plan's five-year rate freeze.

Despite the relatively larger (25 per cent) decreases provided for certain
large industrial customers, the relative cost to Con Edison will be only
a small fraction of the revenue cost of the smaller -- and slower -- (10
per cent) decreases provided for Con Edison's other customers, because
large industrial customers constitute only a small portion of Con Edison's
revenue base.

Other significant rate provisions

Earnings Sharing: Common equity earnings in any rate year (12 months
ending March 31) of the five-year plan in excess of 12.9 per cent (net
of shortfalls below 11.9 per cent from prior rate years of the plan) will
be shared, with 50 per cent of the excess being retained for shareholders,
25 per cent being applied to reduce generation plant balances (thereby
reducing potential strandable costs, discussed below), and 25 per cent
being applied to benefit customers through rate reductions or otherwise
as determined by the PSC. The earnings sharing provision will cease to
apply beginning with the first rate year (i) in which Con Edison has sold
to third parties, pursuant to the divestiture requirement discussed below,
50 per cent or more of its in-City generating capacity or (ii) in which
15 per cent or more of Con Edison's service area peak load (exclusive of
customers of NYPA) is supplied by other than Con Edison, pursuant to the
retail access provisions discussed below.

Exceptions to Rate Freeze: Notwithstanding the freeze, Con Edison will
be permitted, subject to certain thresholds, to defer and recover in rate
adjustments to be implemented in the third and fifth rate years of the
plan (1) increases in annual utility costs resulting from changes in law,
including federal, state and local income tax laws (above a $7.5 million
threshold), (2) increases in local property taxes above levels estimated
in the Con Edison Settlement Agreement, (3) Superfund and other environmental
costs above certain levels, (4) the effects of inflation above 4 per cent
annually, on a net cumulative basis, and (5) certain extraordinary expense
or capital items. In addition, Con Edison may seek a general rate increase
if its forecast return on common equity should fall below 8 per cent (calculated
on a pro forma basis assuming a common equity capitalization of 52 per
cent). Moreover, Con Edison's charges for delivery service to customers
of NYPA will be increased by $45 million over the five years of the rate
plan, and the system benefits charge discussed below will not be subject
to the rate freeze.

Retail Access Schedule

The plan, as modified by Con Edison, provides for an initial program
offering retail access beginning June 1, 1998 to over 70,000 customers
from all service classifications, with an aggregate demand of approximately
1,000 MW. The plan requires Con Edison to allocate up to $5 million for
customer incentives, including cash payments, to encourage participation
by small customers in this first phase.
The second phase called for by the plan will expand retail access by 1,000
MW, to a total of 2,000 MW, within ten months after the first phase begins
(i.e., by April 1999). "To the extent feasible," this expansion
will begin in December 1998. All customer classes will be encouraged to
participate.

Successive further expansions of 1,000 MW ("or more") each are
scheduled at 12-month intervals following the beginning of the second phase,
with the objective of making retail access available to all customers by
the earlier of December 2001 or 18 months after the ISO contemplated by
the PSC's Opinion No. 96-12 becomes "fully operational."

The Con Edison Settlement Agreement (and by extension, the PSC itself)
expressly recognizes "that even with widespread discussion of retail
access, there has been little actual experience with retail access to date,
particularly on a large scale . . . . Accordingly, the parties acknowledge
that the retail access objectives and phase-in dates specified herein are
targets and that flexibility to change the program schedule indicated herein
as issues and obstacles are addressed more slowly (or more rapidly) than
anticipated is essential. The schedule, therefore, will (with appropriate
PSC oversight) be subject to adjustment . . . to address these developments.
(Con Edison Settlement Agreement, § III.4 at 35-36.)

Rate Design And Back-Out Rates

Rate design
The plan introduces a number of significant changes in rate design for
Con Edison's electric customers. The Revenue per Customer/Electric Revenue
Adjustment Mechanism provision was eliminated effective April 1, 1997.
This provision in the prior rates was intended to eliminate the effect
of weather (positive or negative), as adjusted for changes in the number
of electric customers, from Con Edison's electric revenues. The Partial
Passthrough Fuel Adjustment Clause, which provides incentives or penalties
for meeting or not meeting fuel efficiency targets, is continued, but incentives
for demand-side management and customer service are replaced with a penalty-only
provision for deficiencies in customer service and reliability. Other rate
design features of the plan include:
Minimum Charges: The customer charge applicable to residential and small
commercial electric customers will increase by $0.57 per month on April
1 in each of the five rate years of the plan. A minimum monthly charge
will be implemented for all demand-billed customers.
Unbundled Tariffs: The plan requires Con Edison to file "unbundled"
tariffs for all electric service classifications, to become effective April
1, 1998. The unbundled tariffs will disaggregate the major cost components
of Con Edison's electric system: generation capacity, energy, transmission
and distribution. The unbundled tariffs will also include a separate component
for the SBC discussed below.
The unbundled tariffs are, for the time being, primarily informational
for customers which do not participate in the retail access program discussed
above. They do not otherwise permit customers to purchase individual components
of Con Edison's service. However, they are a step in that direction. The
Con Edison Settlement Agreement states "The unbundling process begun
in this settlement agreement is expected ultimately to lead to customers
having the ability to choose from among the unbundled cost elements set
forth in the tariffs. The Commission will not be precluded from implementing
such service unbundling following approval of this settlement agreement."
(Con Edison Settlement Agreement, § II.20(ii) at 20.)
Low Income Rate: The plan continues, through Rate Year Five, a low-income
fixed customer charge of $5.00 per month for approximately 32,000 customers
who also receive public assistance.

System Benefits Charge or SBC: As discussed below, the plan introduces
a new funding mechanism for the costs of research and development, energy
efficiency, low income and environmental programs which might not otherwise
be recoverable in a competitive environment. The SBC will be a separately
stated cost component and will not be subject to the plan's rate freeze.

Back-out rates
The transportation/delivery service rate for retail access customers will
be equal to Con Edison's full service rate for the applicable service classification,
minus adjustments to the energy and generation capacity components of the
full service tariff.
Prior to the establishment of a fully operational ISO, the energy credit,
or adjustments, would equal Con Edison's buy-back energy tariff rate (which
will average 2.5 cents/KWH at transmission voltages, and about 2.7 cents/KWH
at secondary voltages, during the second rate year (the 12 months beginning
April 1, 1998)) and the capacity credit would be based on revenues from
sales of Con Edison's capacity plus certain additional savings. After the
ISO is fully operational, the energy and capacity credits will equal the
market value for energy and capacity, respectively. In no event will the
energy or capacity credits exceed the energy or generation capacity components,
respectively, of the applicable full service tariff.

Generation Divestiture/Market Power Issues
The plan requires Con Edison to divest at least 50 per cent of its generating
capacity located in New York City ("in-City generating capacity")
to unaffiliated third parties no later than December 31, 2002. By the same
date, Con Edison is required to divest or transfer all of its generating
capacity, except its Indian Point nuclear unit and the gas turbines associated
with that unit, to unregulated entities, including unaffiliated third parties
and affiliates of Con Edison. Con Edison was also required to file a detailed
divestiture plan with the PSC by March 1998. Con Edison has made this filing.
Within 90 days after approval of the divestiture plan by the PSC, Con Edison
must initiate the process of selling at least 30 per cent of its in-City
generating capacity.

The rationale for requiring Con Edison to divest at least half of its in-City
generating capacity to unaffiliated third parties is that roughly half
of New York City's peak demand must be met with in-City generating capacity
because of transmission limitations. Most of the in-City generating capacity
is presently owned by Con Edison. By placing in other hands sufficient
in-City generating capacity to meet the in-City requirement, the plan will
require Con Edison to compete for this market.

Corporate Restructuring

Holding company structure
To facilitate the transition to a competitive energy market, the plan contemplates
that, subject to shareholder approval and required governmental approvals,
a holding company be established as the parent company of Con Edison, with
the common stockholders of Con Edison becoming the stockholders of the
holding company. This was accomplished effective January 1, 1998. Concurrently,
Con Edison transferred to the holding company two previously organized
unregulated subsidiaries and a third unregulated subsidiary was organized.
As a result, the initial holding company structure consists of the holding
company parent, Consolidated Edison, Inc., and its four subsidiaries: (1)
the regulated utility, Con Edison, which will retain its historic name,
Consolidated Edison Company of New York, Inc., (2) Consolidated Edison
Solutions, Inc. (formerly known as ProMark Energy, Inc.), an energy marketer
which will operate as an energy services company (an "ESCO")
in the new competitive environment, (3) Consolidated Edison Development,
Inc. (formerly known as Gramercy Development, Inc.), which pursues unregulated
energy-related ventures, and (4) Consolidated Edison Energy, Inc., the
newly-formed subsidiary, which is expected to participate in the competitive
wholesale electricity market. Consolidated Edison, Inc. is permitted to
form additional subsidiaries and to establish one or more intermediate
subsidiary holding companies to hold the stock of its utility subsidiary
and the stock of its unregulated subsidiaries.

Functional realignment
To the extent that Con Edison's fossil-fueled generating stations are retained
within the holding company structure, they will be transferred during the
transition period (i.e., by December 31, 2002) to Consolidated Edison Energy,
Inc. or to another affiliate of Con Edison. For the time being, at least,
Con Edison will retain its Indian Point nuclear unit. Con Edison will also
retain its power purchase contracts with non-utility generators ("IPP
contracts") that are not securitized. (See discussion of securitization
below under "Stranded Cost Recovery" and in Part III of this
Report.) In general, over the five rate years ending March 31, 2002, the
regulated utility, Con Edison, will move toward a pure "wires"
(transmission and distribution) business serving only customers within
its service area. However, to the extent that Con Edison continues to own
generation assets or hold IPP contracts, Con Edison will be permitted (i)
to make wholesale electric energy sales outside its service area, (ii)
to make retail and wholesale electric energy sales within its service area,
and (iii) (until Consolidated Edison Solutions, Inc., Con Edison's ESCO
affiliate, has all necessary approvals to do so) to make retail sales outside
Con Edison's service area.

Affiliate Transactions And Competitive Conduct Standards; Royalty

Affiliate transactions
In general, Con Edison must operate at arm's length from its parent company's
unregulated subsidiaries. The unregulated subsidiaries may not occupy the
same building as Con Edison. Transfers of assets or services between Con
Edison and an unregulated subsidiary must be pursuant to a written contract
filed with the PSC. The plan imposes pricing rules for such transfers,
cost allocation rules, restrictions on common officers or employees and
"revolving door" transfers of employees between Con Edison and
the unregulated subsidiaries, and with limited exceptions requires an unregulated
subsidiary to pay substantial compensation to Con Edison for transfers
of employees from Con Edison to the subsidiary (25 per cent of the employee's
annual salary for the prior year).

Con Edison is required to raise its debt capital directly and not through
its parent company. Without prior PSC permission, Con Edison may not make
loans to its parent or any of the unregulated subsidiaries, or guarantee,
or pledge its assets as collateral for, the obligations of its parent company
or its affiliates. With limited exceptions, Con Edison may not pay dividends
to its parent company in excess of Con Edison's income available for dividends
calculated on a two-year rolling average basis. Con Edison must certify
annually that it has retained or otherwise has access to sufficient capital
to maintain and upgrade its system in order to continue the provision of
safe and reliable service.

Competitive Conduct Standards
There are no restrictions on the use of the name, "Con Edison"
by the parent company or its unregulated subsidiaries, or on the use of
common names, trade names, trademarks, service marks or derivatives, or
on identifying the affiliation among these entities. However, Con Edison
is prohibited from providing sales leads for customers in its service area
to its affiliates, and from promoting its affiliates' products or services
within Con Edison's service area. Con Edison must apply its tariffs in
a non-discriminatory manner and offer equal access to competitive information
relative to its service area. A mechanism is provided for complaints by
competitors and sanctions against Con Edison in the event of violations
of these competitive conduct standards.

Royalty
The plan, and its approval by the PSC, lay to rest, for Con Edison at least,
the "royalty" issue, which has been the subject of considerable
litigation between New York utilities and the PSC in recent years. Under
the royalty theory, unregulated affiliates of a utility enjoy intangible
benefits from their association with a regulated utility, in the form of
good will, name recognition, credit standing, etc. These benefits, according
to the theory, constitute an asset to which the customers of the regulated
utility have contributed, and for which they should be compensated, either
through a direct payment from the unregulated affiliate, or through the
imputation of such a payment, which would offset the revenue requirement
to be raised from customer charges for utility service. The plan provides:
"The rate plan covers all royalties that otherwise would be credited
to . . . [Con Edison's] customers, at any time, including after the expiration
of the agreement." (Con Edison Settlement Agreement, § V.12 at
51.) The rate plan does not provide for any separate royalty payment or
imputation.

Stranded Cost Recovery

Definition and magnitude
The PSC's Opinion No. 96-12 and the Con Edison Settlement Agreement define
strandable costs as "those costs incurred by utilities that may become
unrecoverable during the transition from regulation to a competitive market
for electricity." The parties to the Con Edison Settlement Agreement
did not agree on any estimate of the amount of such costs, but Con Edison's
Annual Report for the year ended December 31, 1996 stated: The Company
estimates that, on a present value basis, its electric strandable costs
could be between $4.7 billion and $6.2 billion, including an estimated
$650 million relating to its fossil-fueled power plants, $1.1 billion relating
to its nuclear generating operations (including decommissioning costs)
and $3 billion to $4.5 billion relating to capacity charges under the Company's
contracts with NUGs [IPPs]." (Annual Report at 21.) The Annual Report
identifies these estimates as forward-looking statements which could be
materially different from actual stranded costs.

Recovery mechanisms
The Con Edison Settlement Agreement provides a number of mechanisms for
the mitigation and ultimate recovery of strandable costs. While it puts
Con Edison "at risk" for a portion of these costs, it also provides
mechanisms for reducing or eliminating the "at risk" portion,
and even for possible recovery of any residual "at risk" portion
.
Mitigation Opportunities:
(i) Con Edison agreed to reduce its generation plant balances by a total
of $75 million of "extra" depreciation, in addition to normal
depreciation, during Rate Years One through Five.
(ii) Under the earnings sharing provision described above, 25 per cent
of the revenue equivalent of the "excess" earnings will be applied
to reduce generation plant balances.
(iii) IPP contract mitigation efforts (through renegotiation, termination,
"buyout", or "buy down") will continue. The costs of
such mitigation will be deferred for recovery after Rate Year Five. As
an incentive, Con Edison will retain the full reductions in fixed IPP costs
through Rate Year Five and 30 per cent of reductions in variable IPP costs
for 18 months. After the end of Rate Year Five, the net benefits of such
IPP contract mitigation will be allocated 25 per cent to the reduction
of generation plant balances and 75 per cent directly to rates in a manner
to be determined by the PSC.
(iv) The first $50 million of net after-tax gains realized by Con Edison
from the divestiture of generating capacity as described above will be
retained by Con Edison. Any additional after-tax gains or losses will be
deferred. Following the end of Rate Year Five (March 31, 2002) Con Edison
will reconcile the remaining plant book values to the market values defined
by the divestiture process, including deferred gains and losses and excluding
any gains retained by Con Edison. The resulting balance (positive or negative)
will be reflected in rates following Rate Year Five as described below.

"At Risk" Provision:
(i) Con Edison will be "at risk" for the disallowance of recovery
of the lesser of:
10 per cent of the actual or then estimated (on a net present value basis)
above-market costs in each rate year after Rate Year Five of Con Edison's
IPP contracts, and

 a maximum of $300 million (net present value at the end of Rate Year
Five), subject to possible reduction of the amount at risk pursuant to
paragraphs (ii), (iii) and (iv) immediately below.
(ii) The total reduction in IPP contract costs after Rate Year Five resulting
from Con Edison's mitigation efforts during Rate Years One through Five
(excluding any reductions in variable IPP costs that may continue to be
retained by Con Edison pursuant to paragraph (iii) under "Mitigation
Opportunities" above), plus any reductions in IPP costs flowed through
to customers during Rate Years One through Five, will be credited as a
reduction in the "at risk" amount.
(iii) Ten per cent of the proceeds of sale of Con Edison's generating facilities
to third parties pursuant to the divestiture requirement described above
will also be credited as a reduction of the "at risk" amount.
(iv) To the extent that the "at risk" amount is not completely
eliminated pursuant to the immediately preceding paragraphs (ii) and (iii),
Con Edison may nevertheless be permitted a reasonable opportunity to recover
such remaining "at risk" costs, depending on the PSC's assessment
of Con Edison's good-faith efforts to implement the provisions of the Con
Edison Settlement Agreement leading to development of a competitive electric
market in Con Edison's service area. In making this assessment the PSC
will consider Con Edison's performance in the areas of divestiture, retail
access (including compliance with the affiliate transactions rules and
competitive conduct standards outlined above), IPP contract mitigation
and post-Rate Year Five levels of base electric rates.
Non-Bypassable Charge:
Subject to the foregoing "at risk" provision, Con Edison will
be given a reasonable opportunity for recovery of strandable and stranded
costs remaining at March 31, 2002, including a reasonable return on investment.
To accomplish this recovery, Con Edison's rates after March 31, 2002, including
delivery/transportation rates for retail access customers, will reflect
a non-bypassable charge for recovery of these amounts.

Recovery Periods:
In the absence of securitization: the recovery period for IPP contract
mitigation costs and above-market costs will generally be the life of the
related contract; the recovery period for Indian Point nuclear costs, including
decommissioning, will generally be the period ending with the expiration
of the Indian Point 2 operating license in 2013; the recovery period for
stranded fossil generation costs will generally be a 10-year period ending
March 31, 2012; recovery periods for Con Edison's other stranded costs
will be as determined by the PSC. If any of the foregoing costs are securitized,
the recovery period will generally match the life of the related bonds.
Securitization:
The Con Edison Settlement Agreement contemplates that savings realized
through securitization will be passed through to Con Edison's customers,
with a portion possibly allocated to the SBC (discussed below), for energy
efficiency and new clean technologies.

Supplier of Last Resort and Energy Service Company (ESCO) Responsibilities
Among the conditions expressly imposed by the PSC was the condition that
Con Edison is obligated to be the provider of last resort for electric
service during the transition to competition, until relieved of that obligation.
This is consistent with a generic opinion and order previously issued by
the PSC, establishing regulatory policies applicable to ESCOs. (Opinion
No. 97-5, issued May 19, 1997, clarified in Opinion No. 97-17, issued November
18, 1997, Case 94-E-0952.) Opinion No. 97-5 directs that only a transmission
and distribution utility, such as Con Edison, will be allowed to terminate
electric service, even for a customer purchasing electric service from
an ESCO.

To protect system reliability as retail access customers begin to purchase
their electric service from ESCOs, the Con Edison Settlement Agreement
imposes a requirement that ESCOs contract for capacity equal to 118 per
cent of their customers' coincident peak load (i.e., an 18 per cent reserve
capacity requirement), which is the same reserve capacity requirement imposed
on traditional utilities, such as Con Edison. Similarly, until June 1,
1999, ESCOs serving in-City customers are required to contract for generating
capacity from in-City sources equal to no less than 70 per cent of the
in-City peak load to be served by such ESCOs, with Con Edison being required
to maintain existing in-City generating capacity sufficient to bring the
ESCOs' in-City generating capacity up to 80 per cent of their peak load.
After June 1, 1999, unless the ISO has established generation capacity
rules for New York City, the ESCOs' in-City generating capacity requirement
will increase to 80 per cent, unless the PSC orders otherwise.

Social/Environmental Programs

Environmental programs
The Con Edison Settlement Agreement commits Con Edison and the DPS Staff
to work with ESCOs and others to develop and implement, where feasible,
a meaningful and cost-effective approach to providing customers with fuel
mix and emission characteristics of the generation sources relied on by
each "load serving entity," with a view to allowing customers
to choose, to the extent they wish, between "green" power and
less benign sources. Con Edison also agrees to develop detailed annual
forecasts of major transmission and distribution projects (with specific
details for projects of $10 million or more), to consider and implement
cost-effective alternatives to such projects, and to consider new technologies
and other means to minimize costs and environmental impacts of transmission
and distribution projects.

The Con Edison Settlement Agreement incorporates Con Edison's support for
the adoption of improved building codes and standards as an appropriate
mechanism for improving the energy efficiency of buildings, including its
support of the objectives of the 1995 Model Energy Code.

Low-income assistance
As noted above, the rate plan continues, for Rate Years One through Five,
a low-income customer charge fixed at $5.00 per month. The rate plan also
continues, through October 1999, a low-income energy efficiency program.

Economic development
As noted above, the rate plan itself includes a large (25 per cent) and
immediate electric rate reduction for certain large industrial customers,
continuing through Rate Year Five. The Con Edison Settlement Agreement
provides for phasing-out Con Edison's two location-specific economic development
programs and an expansion of the Business Incentive Rate program, Con Edison's
service area-wide economic development program.

System Benefits Charge
As contemplated by the PSC's Opinion No. 96-12, the Con Edison Settlement
Agreement provides for a "non-bypassable system benefits charge"
as a funding mechanism for costs required to be spent on necessary environmental
and other public policy programs that would not otherwise be recovered
in a competitive market. The SBC funds will be administered by NYSERDA,
the state-wide administrator chosen by the PSC. The SBC will not be subject
to the rate freeze provided for by the Con Edison Settlement Agreement.
The Con Edison Settlement Agreement allocates $111 million to SBC programs
over the three-year period ending March 31, 2001. This expenditure level
is approximately equivalent to an SBC charge of 1 mill (0.1 cent) per KWH
of energy used.

Reliability Incentives/Penalties

As noted above, the rate plan includes a penalty-only provision for
deficiencies in customer service and reliability. Penalties would be up
to 35 basis points on common equity (revenue requirement equivalent) for
any rate year in which the penalty is triggered. Only four of the penalty
criteria (counting for a maximum 10 basis points of penalty) relate to
reliability of service.

Nuclear Generation Issues

Con Edison's nuclear generating unit, Indian Point 2, is excluded, for
the time being at least, from the Con Edison Settlement Agreement's generation
divestiture requirement. This exclusion is presumably related to the potential
issues that might arise under the Nuclear Regulatory Commission's licensing
and financial responsibility requirements if safety and decommissioning
costs for a power reactor were no longer supported by cost-of-service-based
rates, as well as to the special problems involved in transferring a nuclear
operating license. The PSC is continuing to consider the appropriate treatment
of nuclear generating units in a competitive environment.

Orange & Rockland Utilities, Inc.

On October 1, 1996, Orange & Rockland Utilities, Inc. ("O&R")
filed its initial rate and restructuring plan. An initial settlement agreement
was signed on March 25, 1997. Following issuance of a recommended decision
on July 2, 1997, O&R filed a revised settlement agreement on November
6, 1997. The PSC issued an abbreviated order approving the revised settlement
agreement on November 26, 1997. On December 31, 1997 the PSC issued Opinion
No. 97-20 approving the revised settlement agreement. In February, 1998
O&R filed unbundled proposed rates, which are intended to be revenue
neutral, and an embedded cost of service study. The revised Settlement
Agreement is referred to as the O&R Restructuring Plan in this Report.

Rate Plan

Duration

The effective date of the proposed rate plan is December 1, 1997. It
continues for four years.

At the time of the effectiveness of new rates, O&R expanded its
existing energy-only PowerPick Program (an existing retail access program
for certain customers) to all large industrial customers. On May 1, 1998,
O&R further expanded this energy-only retail access program to all
other customers. Provided that the ISO has become operational by May 1,
1999, O&R will further expand its retail access program at that time
to cover both energy and capacity.

Rate Design and Back-out Rates

(a) Back-out rates are not included in the O&R Restructuring Plan
because the unbundling phase of the proceeding will identify the amount
of fixed production costs that will be backed-out of rates and the formula
for determining the amount of such costs that will be recoverable through
a CTC (assuming divestiture of generation assets is delayed beyond May
1, 1999).
(b) Until full retail access is achieved, energy costs will be collected
through the Fuel Adjustment Clause ("FAC") and the fixed cost
of generation through base rates.
(c) Mandatory time of use ("TOU") rates for residential customers
and peak activated rates ("PAR") will be phased-out.
(d) The Independent Power Producers of New York, Inc. and ENRON Capital
and Trade Resources, two parties to the O&R restructuring proceeding
before the PSC, proposed rate design changes which would entail a significant
reduction in the unit cost of electricity for residential customers with
a corresponding increase in the customer's monthly charge. These proposed
changes had the intent of reducing the cost of using electricity without
reducing overall revenue to the company. The proposed changes, however,
were not accepted by the PSC, at least in part because small users' overall
cost would not decrease, but would increase. The PSC indicated a willingness
to look further at this issue.
(e) A rate plan is adopted which will allocate a greater share of the rate
reductions to industrial customers so that they have an opportunity to
realize an average price of 6 cents per KWH.

Generation Divestiture/Market Power Issues

O&R agreed to divest all of its generation assets, including hydroelectric
and gas turbines. Generation assets are to be divested as soon as possible.
Expected net gains to O&R from such divestiture are to be split between
customers and shareholders as follows: 25 per cent to shareholders, 75
per cent to customers, if O&R selects the winning bidder before May
1, 1999. Net losses would be shared five per cent to shareholders and 95
per cent to customers. After that date, the shareholder/customer split
is 20 per cent/80 per cent of the net gains and losses. The customers'
share of any gain to O&R on such sales is to be allocated for the benefit
of customers, other than large industrial customers, up to a level necessary
to produce five per cent rate reductions. This differential sharing is
intended to encourage completion of the sale prior to May 1, 1999. There
is a cap of $20 million (the New York State portion of the assets) on the
shareholders' gain.
O&R has advised the PSC that it will not participate as a buyer in
the auction of its generation assets. O&R agrees not to own generation
in the O & R service territory for 10 years.

Corporate Restructuring

O&R agreed to seek approvals that would allow it to form a registered
holding company. At the time the generation operations are separated from
the transmission and distribution business, O&R will be authorized
to continue to provide basic energy services, either through the existing,
regulated company, which is referred to in this Report as the "Delivery
Company," or through an affiliated energy services company ("ESCO").

No explicit royalty, to benefit the Delivery Company's customers, will
be charged affiliates for the use of the O&R name as the benefit of
such a royalty has been subsumed in the rate plan of rates for O&R.

Competitive Conduct Standards and Affiliate Transactions

(a) Affiliated subsidiaries may use the parent holding company's name
or the Delivery Company's names, trademarks and derivatives of names and
identify themselves with the holding company or the Delivery Company. The
Delivery Company may not promote its affiliates.
(b) The Delivery Company will not provide preferential treatment to its
marketing affiliate or the affiliates' customers.
(c) The Delivery Company will provide its services at non-discriminatory
rates to all persons.
(d) The Delivery Company will not disclose to its affiliate any customer
or market information relative to its service territory, including but
not limited to customer lists.
(e) There are no specific royalties due to the Delivery Company from the
unregulated affiliates beyond what is already implicitly included in the
Delivery Company's rate levels set forth in the O&R Restructuring Plan.
(f) The DPS Staff shall have access to the books and records of the holding
company, the Delivery Company and affiliates to audit and monitor transactions
between the Delivery Company and such affiliates, to the extent the holding
company possesses such records.
(g) The Delivery Company and affiliated subsidiaries of the holding company
must be operated as separate entities, with separate books of account and
separate offices.
(h) Any discount or special arrangement offered by the Delivery Company
to an affiliate or a customer of an affiliate must be offered to all similarly
situated merchants.
(i) Transfers of assets between the Delivery Company and an affiliate will
not require prior PSC approval, other than transfers of assets from the
Delivery Company which are subject to Public Service Law § 70. Assets,
other than generating stations, shall be transferred at the higher of net
book value or fair market value.
(j) The Delivery Company and affiliates must have separate personnel and
officers of the Delivery Company may not be officers of the ESCO.
(k) Corporate services, such as corporate governance, administrative, legal,
purchasing and accounting, may be provided by the holding company to affiliates
at the fully-loaded cost.

Stranded Cost Recovery

The O&R Restructuring Plan provides O&R an opportunity to recover
through a competitive transition charge ("CTC") four types of
stranded assets during the transition period. The vast majority of such
stranded assets are associated with above-market generation costs. These
stranded assets costs are to be collected through a CTC, beginning May
1, 1999, but only in the event O&R is not able to auction its generating
assets prior to that date, or if O&R is delayed in completing the sales
transaction. Twenty-five per cent of production labor expenses and property
taxes would be at risk in the competitive market. If the auction is not
completed by May 1, 2000, 35 per cent of those costs would be at risk.
If the auction is not completed by October 31, 2000, the CTC will expire
and O&R will be required to obtain PSC authorization to continue it.

Supplier of Last Resort and Energy Service Company (ESCO) Responsibilities

(a) O&R will continue to be supplier of last resort, but by May
1, 1999 the PSC expects to have reviewed this issue further.
(b) The O&R marketing affiliate will not be precluded from competing
during the period prior to commencement of full retail competition.

Social/Environmental Programs

Environmental programs

Rate design will be modified to eliminate mandatory TOU rates for residential
customers and mandatory PAR for industrial and large commercial customers.
The rate design supported by IPPNY/ENRON, described above in Section 3
of this Subpart, is not approved at this time. The PSC may readdress this
rate at a later time.

Low-income assistance

There will be a four-year energy efficiency and assistance program,
with a cost of $400,000 for approximately 400 customers located in the
Port Jervis area. There will also be a low income aggregation pilot program,
with funding up to $200,000.

Economic development

(i) The flex rate and economic development provisions already approved
by the PSC will continue in effect during the term of the Rate Plan.
(ii) Existing NYPA Economic Development Power and High-load Factor customers
are exempt from imposition of stranded costs.
(iii) O&R agreed to design and file a flex rate tariff for commercial
and industrial customers who pose a serious threat of relocating or closing
their facilities. The PSC approved this tariff on April 15, 1998. Such
customers must also be receiving a comprehensive package of economic incentives
from a state or local authority.

System Benefits Change

The SBC is to be 1 mill/KWH. For the first three years of the O&R
Restructuring Plan, the SBC will be included in base rates. When the rates
are unbundled, it will become a non-bypassable charge. The PSC has appointed
NYSERDA to administer most of the SBC-funded programs. Funding levels for
the fourth year will be addressed by the PSC subsequently. The SBC is expected
to produce $3.3 million annually in revenues ($9.9 million over three years),
of which $2.4 million will be spent on energy efficiency programs. The
PSC also allows O&R to eliminate $1 million per year of expenditures
on energy efficiency programs previously included in rates.

Reliability Incentives/Penalties

O&R must continue to perform under performance standards established
in case 95-E-0491. The weighted O&R company-wide interruptions duration
target is 1.46 hours/interruption. O&R must meet this target. If it
does not, the sharing threshold, concerning sharing of earnings between
shareholders and rate payers, is reduced by five basis points.

Nuclear Generation Issues

Nuclear generation issues are not addressed in the O&R Restructuring
Plan nor in PSC Opinion No. 97-20, because O&R does not have any investment
in nuclear power plants.

Central Hudson Gas & Electric Corporation

On October 1, 1996, Central Hudson Gas & Electric Corporation ("CHG&E")
filed its restructuring plan with the PSC. An initial settlement agreement
was filed on March 12, 1997. On July 1, 1997, PSC Administrative Law Judge
Rafael A. Epstein issued a Recommended Decision. CHG&E and certain
other parties signed the Amended and Restated Settlement Agreement ("CHG&E
Restructuring Plan") on January 2, 1998. On February 19, 1998, the
PSC issued an abbreviated order approving the CHG&E Restructuring Plan
agreement. The PSC's detailed opinion approving the CHG&E Restructuring
Plan is expected to be issued in May, 1998.

Rate Plan

Duration

CHG&E agreed in the CHG&E Restructuring Plan not to file a request
to increase base electric rates to be effective prior to June 30, 2001.

Scheduled reductions (to base rates)

In general, there are no scheduled rate reductions for CHG&E customers
during the three and a half years of the CHG&E Restructuring Plan.
Industrial customers in Service Class Tariff No. 13, which elect to enter
into requirements contracts extending through June 30, 2001, however, are
entitled to a five per cent rate reduction upon entering into the contracts.

While the CHG&E Restructuring Plan does not provide for specific rate
reductions for residential, commercial and small industrial customers,
it is expected that at least some of these customers will receive reductions
in electric prices as a result of, among other causes, participation in
retail access pursuant to the phase-in schedule described below. These
price reductions are referred to as "customer benefits" in the
CHG&E Restructuring Plan. Those price reductions are allocated as follows:
Residential$3.5 million/year
Commercial/small industrial$3.5 million/year
Large industrial (S.C. Tariff No. 13)$3.0 million/year

Retail Access Schedule

CommencementInitialProgramFull
Date per cent of CustomersPhase-In
ResidentialSept. 19988 per centJuly 1, 2001
Commercial/Small indus.Sept. 19988 per centJuly 1, 2001
Large industrial Sept. 199812-18 per centJuly 1, 2001
The phase-in of retail choice for residential, commercial, small industrial
and large industrial customers is capped at the maximum levels noted above
through the end of the transition period covered by the CHG&E Restructuring
Plan, namely, through June 30, 2001. The caps are eliminated at the end
of that period. The participation of these customer groups in retail choice
will lead to lost revenues for CHG&E which will be capped by the "customer
benefits" limits described immediately above.

Rate Design

(a) General

Each year during the term of the CHG&E Restructuring Plan (i.e.,
to June 30, 2001), CHG&E customers are expected to obtain price reductions
in an annual amounts totaling $10 million. This annual total will be allocated
among customer classes as set forth above in connection with rate reductions
and retail access options. CHG&E will continue to remain under Statement
of Financial Accounting Standards ("SFAS") No. 71 during the
term of the CHG&E Restructuring Plan. The FAC, or its successor once
the ISO is operational, as well as other aspects of traditional PSC rate
making, will continue to operate to change rates based on short-term market
conditions for fuel purchases and other short-term changes in costs to
CHG&E. Other provisions of traditional CHG&E rate making will be
continued under the CHG&E Restructuring Plan.

The return on equity ("ROE") standard will be adjusted at the
time of CHG&E's divestiture of fossil generating assets. Prior to that
time, CHG&E's ROE will be capped at 10.6 per cent. After the divestiture,
ROE over 10.6 per cent earned for the entire settlement period will be
used to offset stranded costs and any amount in excess of that will be
used to fund price reductions for consumers. Bids by CHG&E for sales
to the Power Exchange, an energy auction that may be established as a part
of industry restructuring from its own fossil-fueled generation facilities,
may not be below cost of fuel plus variable operation and maintenance expenses
("O & M").

There are three rate and retail access options available to large industrial
customers (S.C. Tariff No. 13):
(i) Customers not wishing to enter into requirements contract may continue
to receive service under S.C. Tariff No. 13, with or without selecting
retail access.
(ii) Industrial customers willing to enter into full or partial requirements
relationships may enter into such contracts, cancelable on one year's notice.
There are three options:
 Full requirements customers, who agree to contract for the term of the
CHG&E Restructuring Plan, may select a five per cent rate reduction.
 Partial requirements customers may select a 5 per cent rate reduction
together with an Energy Value Option Plan ("EVOP"), described
below.
 Partial requirements customers may also select retail access options,
but in doing so they forego the five per cent rate reduction.

The EVOP option permits S.C. Tariff No. 13 customers to obtain energy
from suppliers other than CHG&E. These customers are allowed to take
their pro-rata share of CHG&E's portfolio of nuclear and hydro power,
which will represent approximately 20 per cent of such customers' energy
requirements.

CHG&E will expand the availability of its economic development growth
incentive tariff by (1) increasing the size of the pool available for sale
under this tariff from 50 MW to 75 MW, (2) expanding the eligibility of
the tariff by adding additional customers and (3) making other changes.

Generation Divestiture/Market Power Issues

CHG&E will auction its fossil generation and will take commercially
reasonable steps to complete the auctions' closings by June 30, 2001. A
CHG&E affiliate is permitted to participate as a bidder; in that event,
however, an independent auctioneer will be employed to ensure fairness
and an arm's-length transaction.

CHG&E agreed not to own (within the regulated entity) central station
generation (exclusive of on-site generation) within its service territory
in addition to that already owned. CHG&E will not own, for a period
of five years following the transfer of fossil generation, more than 1,700
MW of any form of generation capability at the Roseton/Danskammer site.

If a CHG&E affiliate does not participate in the auction, CHG&E
shall receive an auction incentive on any gain over net book value, equal
to 10 per cent of the total proceeds over net book value up to a $17.5
million cap.

Corporate Restructuring

CHG&E will functionally separate its generation facilities (apart
from the Nine Mile Point No. 2 plant, combustion turbines and hydro) from
its transmission/distribution facilities. CHG&E will establish a holding
company that will own, inter alia, (i) a PSC-regulated electric and gas
transmission and distribution company ("T&D Company") that
may contain generation assets, (ii) an "unregulated" generation
company that owns or operates generation assets within and outside New
York, and (iii) an unregulated affiliate that owns and operates IPP facilities
and provides other, energy-related services. The generation company described
in "(ii)" immediately above will be subject to regulation by
the PSC no greater than PSC regulation of other owners of legally comparable
facilities. The unregulated affiliate in "(iii)" may function
as an ESCO and as a power marketer.

The regulated T&D Company will offer regulated and market-based wholesale
energy services and retail energy services. It may also provide energy
services company ("ESCO")-type services.

Competitive Conduct Standards and Affiliate Transactions

The officers of the CHG&E holding company, apart from the Chairman
and President, will not also be officers of an unregulated ESCO affiliate.
The regulated part of CHG&E, the T&D Company, will not provide
market information or sales information to any affiliate and will not give
the appearance that it acts for any affiliate. The T&D Company may
not give an affiliate preference over non-affiliated customers. The T&D
Company, initially, will provide administrative services for itself, the
CHG&E holding company and affiliates.

A dispute resolution process is established in Appendix "B" to
the PSC's February 19, 1998 order.

Stranded Cost Recovery

Stranded cost recovery will commence at the time of CHG&E's next
rate case, which will take effect on or after June 30, 2001. Net proceeds
from the auction of generation assets, in excess of book value and net
of the auction incentive, will be allocated as follows:
 First, to offset fossil generation stranded costs not recognized in the
auction (such as "regulatory assets");

 Second, to reduce book costs of Nine Mile Point No. 2 plant; and

 Third, to provide rate payer benefits.

If the auction proceeds are below net book value, the difference will
be added to stranded costs.

Recovery of stranded costs will be through a competitively neutral non-bypassable
wires charge. A CTC will be established at a level equal to approximately
50 per cent of CHG&E's non-fuel production costs. The costs to CHG&E
arising from residential, commercial and small-industrial customers participation
in retail access during the period of the CHG&E Restructuring Plan
will be recovered through the CTC. A goal will be to minimize cost shifting
among and within classes of customers. All customers will be eligible for
full retail access on July 1, 2001.

Supplier of Last Resort

CHG&E will remain the supplier of last resort during the term of
the CHG&E Restructuring Plan.

Social/Environmental Programs

Environmental programs

The parties to the CHG&E Restructuring Plan agree to participate
in a generic proceeding to develop means of providing customers with information
on the fuel mix and emissions characteristics of generation. Time of use
meters will not be required for customers not now using them.
Low-income assistance

There is no specific discussion of a low-income rate or assistance program
in the CHG&E Restructuring Plan.
Economic development

CHG&E will expand the size of its growth incentive plan by 25 MW;
it will increase the size of the incentive discount for S.C. Tariff No.
13 customers to 28 per cent; and it will make a growth discount program
available for S.C. Tariff No. 3 customers (namely, Large Power, Primary
Service customers). In general, these changes will end on June 30, 2001.

System Benefits Charge

CHG&E is expected to collect $4.1 million annually for SBC  funded
programs over the next three years. Funding will be a one mill/KWH charge
for three years. A statewide administrator, the New York State Energy Research
and Development Authority, will administer the SBC-funded programs.

Reliability Incentives/Penalties

CHG&E agreed in the CHG&E Restructuring Plan to a Service Quality
Incentive Plan ("SQIP") which includes provisions addressing
reliability. The reliability part of the SQIP was designed to reduce the
total number of interruptions and the length of time each interruption
lasts. If the score for the entire SQIP, including elements other than
reliability, is below a target level agreed to by CHG&E, the T&D
Company will suffer a reduction in permissible earnings.

Nuclear Generation Issues

The costs of CHG&Es share of the Nine Mile Point No. 2 plant, will
continue to be included in CHG&Es rate base and as expense items, consistent
with the PSC's past treatment of such items. Following July 1, 2001, these
costs will continue to be recovered by the regulated T&D Company. CHG&E
agrees to participate in "good faith discussions" related to
a future state-wide nuclear power plant resolution.

New York State Electric & Gas Corporation

On October 9, 1997, New York State Electric & Gas Corporation ("NYSEG")
filed an Agreement Concerning the Competitive Rate and Restructuring Plan
of New York State Electric & Gas Corporation, dated October 9, 1997
("NYSEG Agreement"), with the PSC establishing a framework under
which NYSEG would restructure its activities, among other things, to implement
retail competition in its service territory and institute rate reductions
for its retail customers. A Recommended Decision, concerning this settlement
reflected in the NYSEG Agreement was issued by PSC Administrative Law Judge
Jeffrey Stockholm on December 3, 1997. On January 27, 1998, the PSC issued
an abbreviated order approving the settlement, subject to certain conditions
and modifications contained in the order. On March 5, 1998, the PSC issued
an order and opinion (Opinion No. 98-6) explaining its decision in the
January 27, 1998 order.

Rate Plan

Duration
In general, rate terms of the NYSEG Agreement cover a five-year period
(the "Price Cap Period"). However, certain provisions extend
beyond the five-year Price Cap Period. The effective date of the implementing
tariffs for Year One of the Price Cap Period was March 3, 1998.

Scheduled reductions (to base rates)

NYSEG has agreed to forego two rate increases previously approved by
the PSC in 1995 scheduled to occur in Years Two and Three of the previous
settlement period established in a prior 1995 settlement of electric rate
issues; this eliminates an approximate seven per cent price increase for
residential and commercial customers. In addition, NYSEG will reduce customer
rates as follows:

(i) Large customers (i.e., industrial customers with average, annual peak
demands of 500 KW or greater and all demand billed customers with average,
annual load factors of at least 68 per cent) will receive annual electric
rate reductions of 5 per cent on average effective for each year of the
Price Cap Period. (Customers with negotiated or incentive rates ("Flex
Rate and Incentive Customers") are not eligible for the rate reductions
until their tariffs or contracts expire or unless such tariffs or contracts
permit them to be eligible for the rate reductions.)

(ii) All industrial and commercial customers not eligible for the rate
cuts described immediately above will receive a rate reduction of five
per cent effective for the fifth year of the Price Cap Period. (Flex Rate
Customers are not eligible for the rate reductions until their tariffs
or contracts expire or unless such tariffs or contracts permit them to
be eligible for the rate reductions.)

Retail Access Schedule

Retail access will be made available to NYSEG's customers in three groups:

(a) Beginning on November 1, 1997, NYSEG implemented a targeted customer
choice pilot program in compliance with the PSC's "Order Establishing
Retail Access Pilot Program" issued on June 23, 1997 in Case 96-E-0948
 Petition of Dairylea Cooperative, Inc. to Establish Open-Access Pilot
Program for Farm and Food Processor Electricity Customers.
(b) Beginning on August 1, 1998, retail access will be available to: (i)
all customers in the City of Norwich and the Lockport Division, subject
to minimum load and aggregation requirements; and (ii) all industrial customers
which are not eligible for the 5 per cent annual rate decreases and not
taking service under special contracts. Eligible customers which choose
a new electricity supplier will have power delivered by NYSEG from the
new supplier by no later than December 31, 1998.

(c) Beginning on August 1, 1999, full retail access will be available
to all remaining eligible NYSEG customers, e.g., other than Flex Rate and
Incentive Customers, provided that an Independent System Operator is operating.
Flex Rate and Incentive Customers will be eligible for retail access after
their contract or tariff expires unless the contract or tariff permits
the customer to become eligible for retail access sooner. Eligible customers
which choose a new electricity supplier will have power delivered by NYSEG
from the new supplier by no later than December 31, 1999.

Rate Design and Back-Out Rates

Rate design

(i) With respect to customers not eligible for the rate reductions described
in Subpart 1.b.i above, NYSEG will freeze their rates for Years One and
Two of the Price Cap Period.
(ii) By February 26, 1998, NYSEG must file marginal cost-based tariffs
applicable to incremental energy usage above historical levels of the industrial
and commercial customers not eligible for the annual five per cent annual
rate reductions described in Section 1.b.i above.
(iii) NYSEG is required to file no later than February 1, 1999, new electric
rate designs for Years Three, Four and Five that address marginal cost-based
pricing for all customer classes. Beginning in Year Three of the Price
Cap Period, NYPA savings for residential customers may be reflected in
the basic service charge.
(iv) NYSEG is required to unbundle its electric retail rates over the five
year Price Cap Period so that they reflect the separate service components
such as the Basic Service Charge (as appropriate), SBCs, the Retail Access
Credit, Power Supply Charges, Transmission, Distribution, Customer Sevice
and the CTC.
(v) All customers, including those who switch suppliers, will be required
to pay a non-bypassable CTC plus any related Gross Receipt Tax ("GRT")
to permit NYSEG to recover the stranded generation costs (discussed in
Subpart 7, below).

Back-out rates

The back-out rates for initial retail access customers and full retail
access customers are as follows:
Initial Retail Access  the retail access credit used to back-out generation
during the period prior to NYSEG selling its non-nuclear generation assets
will be the market price of electricity plus an adder of four tenths of
1 cent ($0.004) per KWH for customers eligible for the annual five per
cent rate reduction described in Section 1.b.i above and an adder of 1
cent per KWH for customers not eligible for the annual five per cent rate
reductions except for Flex Rate and Incentive Customers. The retail access
credit cannot exceed 3 cents per KWH including GRT.

Full Retail Access  the retail access credit used to back-out generation
after NYSEG sells its non-nuclear generation assets will be (a) 3.23 cents
per KWH, including GRT, through July 31, 2000, (b) 3.47 cents per KWH,
including GRT, from August 1, 2000 to July 31, 2001, and (c) 3.71 cents
per KWH, including GRT, from August 1, 2001 until the end of the Price
Cap Period. The retail access credit will be net of the CTC imposed for
stranded costs after NYSEG sells its coal-fueled generation assets. After
the Price Cap Period, all costs (other than the non-bypassable CTC) related
to assets subject to auction or appraisal will be excluded from rates and
all customers will pay the market price of generation plus applicable GRT.
If the auction or appraisal of NYSEG's generation assets is not completed
by August 1, 1999, until the generation assets are sold, the retail access
credit used to back-out generation will be the market price of electricity
plus an adder of four tenths of 1 cent ($0.004) per KWH for customers eligible
for the annual 5 per cent rate reduction described in Section 1.b.i above
and an adder of 1 cent per KWH for customers not eligible for the annual
5 per cent rate reductions except for Flex Rate and Incentive Customers.
The retail access credit cannot exceed 3.23 cents per KWH including GRT.

Generation Divestiture/Market Power Issues

In the NYSEG Agreement, NYSEG undertook to transfer its coal fueled
generation plants to a third party or an affiliate ("GenSub")
in order to promote competition, mitigate stranded costs, and to establish
a fair market value of the plants. NYSEG has agreed, however, that its
GenSub will not participate as a buyer of its generation plants. The value
of the generation plants will be determined in accordance with an auction
designed to obtain the highest market value and to mitigate above market
costs and establish a regulatory asset for the recovery of remaining above
market costs. If no bids are received above the minimum bid requirement,
an appraisal process will be used to value the plants. The auction and
sale or appraisal process must be completed by August 1, 1999. NYSEG is
required to submit an auction and appraisal plan, developed in consultation
with the DPS Staff and parties to the NYSEG Agreement. NYSEG submitted
this plan to the PSC, and the PSC approved such plan on April 24, 1998.
Corporate Restructuring

On April 29, 1998, NYSEG's shareholders approved the formation of a
new holding company, Energy East Corporation. NYSEG will be a regulated,
wholly-owned utility subsidiary of this holding company. NYSEG will functionally
separate its electricity distribution activities from its gas services.
On February 10, 1998 NYSEG transferred its generating assets to NGE Generation,
Inc., which will be a subsidiary of Energy East Corporation.

Competitive Conduct Standards and Affiliate Transactions

(a) The NYSEG Agreement contains numerous standards to govern affiliate
transactions among NYSEG and its affiliates. These standards include provisions
related to the following: (i) separation of business entities conducting
regulated and unregulated activities; (ii) separation of the books and
records of regulated and unregulated business entities; (iii) limitations
on affiliate transactions to protect against cross-subsidies; (iv) limitations
on NYSEG's ability to provide competitive information to affiliates unless
the same information is made available to competitors at the same time
and under the same conditions; (v) DPS Staff's access to the books and
records of NYSEG and, under certain conditions, its major affiliates; (vi)
dispute resolution process for PSC review of a competitor or customer's
complaint that NYSEG has acted in an anticompetitive manner; (vii) certain
limitations on NYSEG's ability to promote an affiliate as service provider
to customers located in NYSEG's service territory; (viii) prohibition on
NYSEG's ability to guarantee the securities of its affiliates or pledge
any of its assets as security of an affiliate's indebtedness; (ix) rules
against NYSEG loaning operating employees to its affiliates; and (x) prohibition
against NYSEG conducting certain competitive behind-the-meter energy services.

(b) The PSC can impose remedial actions on NYSEG for violations of the
competitive conduct standards contained in the NYSEG Agreement.

Stranded Cost Recovery

NYSEG will be permitted to recover through the non-bypassable CTC (over
a period of time to be determined by the PSC after the auction process)
the stranded costs, if any, resulting from the sale of its coal fueled
generation plants (as described in Subpart 4, above). The stranded costs
related to the generation assets will be the difference between the net
book value of the plants (less funded deferred taxes) and the net after-tax
auction proceeds. After the Price Cap Period, NYSEG's regulatory assets
(other than those related to the auction of the coal fueled plants, hydroelectric
facilities, non-utility generators, i.e., IPPs, and nuclear fixed costs
(except if the nuclear assets are auctioned)) will be recovered through
a non-bypassable wires charge (for the life of the amortization period,
contract or license). NYSEG will propose to the co-tenants of the Nine
Mile Point No. 2 plant that it be sold via auction. If they agree, and
the nuclear plant is sold to a non-NYSEG entity, then NYSEG can recover
through a non-bypassable wires charge the difference between the book value
of its ownership interest in the plant (less funded deferred assets) and
the net after-tax auction proceeds for a period determined by the PSC but
not to exceed 15 years.
If during the Price Cap Period NYSEG achieves IPP contract cost savings
through renegotiation or termination, but excluding securitization, 80
per cent of the net savings will be flowed through to customers in a manner
determined by the PSC and NYSEG can retain 20 per cent of the savings.
After the Price Cap Period, pass through to customers of IPP contract savings
will be done in a manner to be determined by PSC.

Supplier of Last Resort and Energy Service Company (ESCO) Responsibilities

NYSEG will be the provider of last resort during the Price Cap Period
unless the PSC changes such status. Upon approval by the PSC, NYSEG may
deny access to any other New York state utility or its load serving affiliate
("LSE") which seeks to serve retail customers in NYSEG's service
territory if NYSEG or its affiliated energy service company is not permitted
(in at least equal or greater proportion) to serve customers in the retail
service territory of the LSE's affiliated utility.

Social/Environmental Programs

Environmental programs

Pursuant to the January 27 order, the NYSEG Agreement includes the environmental
provisions approved in the Con Edison proceeding. The PSC may evaluate
potential ways to accomplish further environmental benefits through environmental
protection and energy efficiency programs.
Low-income assistance

NYSEG will continue its current "Fresh Start" low income assistance
program until a replacement program is approved. Pursuant to the PSC's
March 5, 1998 Opinion No. 98 - 6, NYSEG will file a proposed low income
assistance program designed to provide service to customers known by NYSEG
to receive benefits under the Energy Assistance Program (estimated to be
37,000). The annual cost of this program is estimated at $5 million; $2.5
million of this annual amount, from Rate Year One through Rate Year Three,
will be obtained from the $13 million earmarked in the NYSEG Agreement
for energy efficiency and other programs approved by the PSC for funding
through the SBC.

Economic development

During the Price Cap Period, NYSEG will supplement existing programs
or institute new programs for economic development. For example, NYSEG
will continue existing tariffs for Economic Development Zone Incentive
Rates ("EDZI") but will provide new discounted rates for qualifying
loads of existing and future customers and new zones. In addition, NYSEG
will continue its Economic Revitalization Incentive Rate ("ERI")
tariff but reduce the customer eligibility requirement from a 500 KW to
300 KW billing demand. Also, NYSEG will implement new customer eligibility
requirements for its S.C. Tariff Nos. 13 and 14. Finally, NYSEG will file
a new tariff provision called the Business Retention Incentive to augment
its existing retention and revitalization tariffs (e.g., Self Generation
Deferral Incentive, EDZI, S.C. Tariff No. 13, S.C. Tariff No. 14, and ERI).

System Benefits Charge

Neither the NYSEG Agreement nor the January 27 order specifically addresses
the cost level and mechanism of recovering costs associated with the SBC.
The NYSEG Agreement states, however, that if the PSC determines a mechanism
to recover SBCs in this proceeding or in the separate pending collaborative
undertaking on SBCs in the PSC's Competitive Opportunities Proceeding (which
the PSC has determined), NYSEG and the parties to the NYSEG Agreement will
support use of standard performance contracts with stipulated pricing as
one way to disburse funds for energy efficiency programs. It is now expected
that NYSEG will collect approximately $13.3 million annually, $40 million
over three years, for SBC programs.

Reliability Incentives/Penalties

During the Price Cap Period, an Electric Service Quality Performance
Mechanism will be in place which provides NYSEG with the incentive to render
reliable electric service. NYSEG will be subject to a penalty if service
falls below targeted levels. The mechanism, as modified by PSC Opinion
No. 98  6, uses five indices to measure performance and reliability.

Nuclear Generation Issues

See discussion in Subpart 7 above.

Niagara Mohawk Power Corporation

On July 23, 1997, Niagara Mohawk proposed an amended five-year rate
and restructuring proposal ("PowerChoice") following almost two
years of negotiations addressing an earlier PowerChoice proposal. The July
23, 1997 PowerChoice proposal includes the Master Restructuring Agreement
("MRA"), dated July 9, 1997, between Niagara Mohawk and 16 signing
independent power producers ("SIPPs") that represent about 80
per cent of the utility's above-market outside power purchases. Under PowerChoice,
the SIPPs will collectively own about 25 per cent of Niagara Mohawk after
acquiring newly created common stock.
Niagara Mohawk further amended its PowerChoice proposal on October 10,
1997 in a settlement agreement with 20 parties to its restructuring proceeding.
PSC Administrative Law Judge William Bouteiller recommended adoption of
the modified PowerChoice plan, with several additional modifications, on
December 29, 1997. The PSC approved PowerChoice (Opinion No. 98-8) with
certain changes and conditions on March 20, 1998.
Niagara Mohawk's PowerChoice proposal was issued at a time that the company
found itself in a dire financial situation. In August 1995 Niagara Mohawk
indicated that its contracts with IPPs were damaging the company and that
it would have to restructure the contracts or take "even more severe
actions" to "keep the company financially viable." Niagara
Mohawk's Chairman reported that bankruptcy was an option. The payments
to IPPs, which contributed to this financial condition, had grown from
$198 million in 1990 to $1.01 billion in 1995. Meanwhile, business conditions
in Niagara Mohawk's service territory were stagnant.

Rate Plan

Duration

PowerChoice is a five-year plan. It begins after unbundled tariffs are
in effect and Niagara Mohawk has restructured the individual IPP contracts
referenced in the MRA. Other events must occur before the implementation
of PowerChoice. They include: Niagara Mohawk receiving various approvals
to sell debt and equity and the IPPs obtaining releases from existing contractual
obligations to certain steam hosts. Currently, PowerChoice is forecast
to begin in mid- to late-1998.

Scheduled reductions (to base rates)

The average residential and commercial customer will experience a 3.2
per cent reduction in prices (from 1995 base rates or the most current
twelve-month period, whichever base year results in the lowest first year
level) phased-in over a three-year period. Tariff rates for the industrial
class will be reduced to below $0.06/KWH by 2000, which is a reduction
of 25 per cent relative to 1995 price levels. The vast majority of surcharges
resulting in "back-door" rate increases have been eliminated.

(i) The starting point for establishing unbundled rates that will apply
during PowerChoice is the 1995 actual rates, including all surcharges,
annualized for the base rate increase, or the latest known twelve months'
actual rates, whichever is lower. Prices for transmission and distribution
services will increase throughout the period of PowerChoice. However, increases
in transmission and distribution services for Rate Years One through Three
of the PowerChoice period will be offset by an equivalent reduction in
the CTC to meet overall price reduction goals. In Rate Years Four and Five,
the CTC will be adjusted quarterly for changes in IPP-indexed charges.
Energy and customer service back-out rates have been established. Certain
costs or savings can be deferred for recovery or refund in years four and
five of PowerChoice.
(ii) On May 18, 1998, Niagara Mohawk submitted unbundled tariffs to be
used during PowerChoice. These amended tariffs will become effective upon
not less than 60-days notice.
(iii) Prices in Rate Years Four and Five may be increased by an amount
not to exceed one per cent of the all-in fixed price except for energy.
This "hard" price cap excludes recovery of certain expenses.
Niagara Mohawk must affirmatively seek approval from the PSC to implement
any price increases in Rate Years Four and Five of PowerChoice. In addition,
any rate increase within the one per cent price cap may not exceed the
rate of inflation.
(iv) All customers (except certain NYPA customers and certain on-site generators)
must pay a non-bypassable CTC, or in prescribed circumstances, an exit
fee. Niagara Mohawk will have a reasonable opportunity to recover costs
associated with fossil and hydro units, nuclear assets and the MRA. Niagara
Mohawk has not computed a final stranded cost amount to be collected from
customers. The effect of certain cost factors, including plant auctions
and IPP contract renegotiations, has yet to be determined.
(v) Over the five-year settlement period, it is estimated that Niagara
Mohawk shareholders will have to absorb over $2 billion of stranded costs;
shareholders will thus forgo ROE up to that amount which would otherwise
have been allowable from the MRA regulatory asset. Unlike other investor-owned
utilities, Niagara Mohawk expects little to no return on equity during
the term of PowerChoice.

Back-out rates

The PSC has approved PowerChoice's energy back-out rates for Niagara
Mohawk customers that choose new suppliers. The amount backed out of Niagara
Mohawk's bundled rates will remain in effect until the ISO is in operation
and develops a spot market price. The back-out rate represents estimated
market prices. The energy back-out rate is projected to be approximately
2.5 to 3.0 cents per KWH for the first three years of the PowerChoice settlement
period, depending on the customer's class and location. A customer service
back-out rate, approved by the PSC in January 1998, will be monitored and
updated as necessary.

Generation Divestiture/Market Power Issues

Niagara Mohawk will divest its fossil and hydro generation assets at
auction. Winning bids in the auction would be selected no later than 11
months after PSC approval of an auction plan. Niagara Mohawk may retain
fossil/hydro assets that do not receive positive bids. Niagara Mohawk's
nuclear assets will become part of the surviving regulated company ("RegCo")
-- although functionally separated -- until a statewide nuclear solution
is found. In addition, Niagara Mohawk has 24 months after the date of the
PowerChoice settlement to file a plan with the PSC analyzing all possible
nuclear solutions.

Niagara Mohawk's auction plan was approved by the PSC on April 8, 1998.
Under the approved plan, Niagara Mohawk will offer all its fossil and hydro
assets for sale, comprising 4,217 MWs of capacity, in a two-stage sealed
bid process. The bidding is open to all qualified outside parties. Niagara
Mohawk has announced it would not participate in the auction bidding. Bidders
may submit a bid on the Niagara Mohawk's entire fossil/hydro portfolio,
on individual fossil units, on any of six bundles of hydroelectric plants,
or any combination thereof. Niagara Mohawk operates four fossil-fueled
plants with a combined capacity of 3,256 MWs. In addition, the company
will sell its 300-MW interest in the Roseton Station, operated by Central
Hudson Gas and Electric Corporation. Niagara Mohawk's 72 small hydro units
(a total of 661 MWs) are packaged in groups ranging from five plants to
28. Buyers for these fossil and hydro plants will be selected six months
after the PSC's April 8, 1998 Order approving Niagara Mohawk's auction
plan. Transfer of ownership is expected to take place mid-1999.

The auction plan allows Niagara Mohawk 15 per cent of any gain above net
book value as an incentive to obtain the highest possible prices for its
generation facilities. Niagara Mohawk's Oswego Steam station is subject
to a separate five per cent incentive on proceeds in excess of $100,000.
The Oswego Steam station incentive will increase as the auction value increases.

Corporate Restructuring

Niagara Mohawk is authorized to form a holding company ("HoldCo")
or similar utility parent. It will divest fossil/hydro assets (as discussed
above), and operate a functionally separated transmission, distribution
and gas company, RegCo, referred to above. RegCo may form subsidiaries,
subject to PSC jurisdiction, if desired. The holding company structure
may create lightly regulated and unregulated affiliates of Niagara Mohawk
such as the existing Plum Street Enterprises. Niagara Mohawk may form other
transitional subsidiaries in order to effectuate the fossil/hydro auction.
RegCo must submit annual reports to the PSC concerning: transfers of assets,
cost allocations, employee transfers and employees in common benefit plans.
HoldCo will file a list of SEC reports with the PSC.

Competitive Conduct Standards and Affiliate Transactions

(a) PowerChoice contains rules to govern affiliate transactions among
Niagara Mohawk and its subsidiaries and affiliates. The corporate code
of conduct standards was approved by the PSC and is designed to ensure
separation of business entities conducting regulated and unregulated activities.
RegCo, HoldCo, and HoldCo's other subsidiaries will maintain separate books
and records of account.
(b) Specific provisions include:
(i) RegCo will provide no sales leads to affiliates involving customers
in its service territory;
(ii) RegCo must respond to customer inquiries with a list of all known
energy service companies doing business in its service territory;
(iii) no rate discrimination by RegCo is permitted; and
(iv) Niagara Mohawk and its affiliates may use the corporate name without
specific royalty payments.
(c) Each distinct corporate entity will maintain separate books and records
of account.
(d) The PSC can impose remedial actions on Niagara Mohawk for violation
of the competitive conduct standards contained in PowerChoice.

Stranded Cost Recovery

The PSC will allow Niagara Mohawk a reasonable opportunity to recover
its stranded generation costs and regulatory assets, including costs associated
with its own generation as well as $3.6 billion new debt associated with
the MRA. A non-bypassable CTC will be used to collect these costs. Certain
on-site generators and new municipal systems (and certain recipients of
other allocations) will be subject to access or exit fees established by
amended tariffs filed by Niagara Mohawk and approved by the PSC.
In general, PowerChoice provides a mixed offering of CTC mechanisms to
retail customers for stranded cost recovery. Customers in industrial, commercial
and residential classes will have the option of a fixed CTC during the
five years of PowerChoice.
In addition to the fixed CTC, customers in S.C. Tariff Nos. 1, 2 and 3
will have the option of a floating CTC. Customers in S.C. Tariff No. 3A
(the largest industrial and commercial customers) do not have the floating
CTC option. However, they can choose all-in bundled prices for a five-year
period (with or without options to cancel) in addition to the fixed CTC
option.

Supplier of Last Resort and Energy Service Company Responsibilities

Niagara Mohawk's RegCo will retain the obligation to serve electricity
to all customers in its service territory during the term of PowerChoice.
ESCOs providing electric power to customers during PowerChoice must meet
reasonable standards of operational conduct and acceptable standards of
commercial creditworthiness. ESCOs may choose between a one or two-bill
system.

Social/Environmental Programs

Environmental programs

PowerChoice provides for a SBC to cover demand-side management efforts,
research and development and energy efficiency for low-income customers.
Niagara Mohawk will make $15 million available annually for these programs
for the first three years of PowerChoice. Thereafter, the SBC program would
be revisited and future funding levels would be set.
Niagara Mohawk will provide environmental benefits by retiring 5,000 of
its sulfur dioxide emission allowances and by donating, selling and granting
conservation easements for various parcels of land it owns in the Adirondack
Park. Niagara Mohawk will also help develop windpower and photovoltaic
generation and it will fund a long-term ecological monitoring program.

Low-income assistance

During PowerChoice, Niagara Mohawk will expand its Low-Income Customer
Assistance Affordability Plan ("LICAP"). Under LICAP, Niagara
Mohawk may accept partial payment from a non-public assistance customer.
The settlement budgets between $4.4 million and $5.6 million for this program
for 1998 through 2000.

System Benefits Charge

Niagara Mohawk will collect $45 million over three years for SBC programs.

Reliability Incentives/Penalties

PowerChoice provides for a "Customer Service Performance Incentive"
that is capped at $13.2 million a year. The PSC will monitor complaints
received over a 12-month period (rates of total complaints per 100,000
customers) and apportion penalties within a scaled interval:

Niagara Mohawk has agreed with DPS Staff to develop a program of individual
customer service guarantees. Emphasis initially will be placed on the scheduling
of appointments. In addition, a service interruption frequency, interruption
duration and power quality will be monitored. Penalties, if any, will be
accrued to offset cost deferrals.

Nuclear Generation Issues

Under PowerChoice, Niagara Mohawk will recover costs for each of its
nuclear plants. Niagara Mohawk has agreed to hedge those costs through
a financial swap contract for the first three years of the PowerChoice
period. Each nuclear cost recovery contract is based on the forecasted
going forward costs of each plant. These forecasts will be included in
overall rate goals and may be adjusted in years four and five. If a nuclear
unit is retired during PowerChoice, the nuclear cost recovery contract
will end and the energy associated with the retired unit will be unhedged.
Niagara Mohawk will make a filing to the PSC after PowerChoice to continue
cost recovery for its nuclear units.

Rochester Gas And Electric Corporation

On November 26, 1997, the PSC issued an abbreviated order adopting,
subject to certain conditions and modifications, a settlement ("RG&E
Settlement"), dated October 23, 1997, executed by Rochester Gas and
Electric Corporation ("RG&E") and other interested parties.
The RG&E Settlement constitutes RG&E's restructuring framework
under which it will implement competitive customer retail choice in its
service territory, rate reductions and a corporate reorganization. On January
14, 1998, the PSC issued a detailed order (Opinion No. 98-1) approving
the settlement and providing the PSC's views on certain matters. This order
is the subject of pending litigation in New York Supreme Court. The RG&E
Settlement, as modified by the PSC, is summarized below.

Rate Plan

Duration

The rate reductions under the RG&E Settlement will be for a five
year term beginning on July 1, 1997 through June 30, 2002 ("Settlement
Term").

Scheduled reductions (to base rates)

Under the RG&E Settlement, rates for all customer classes will be
reduced. Large industrial and commercial customers will receive the biggest
decreases over the Settlement Term.

Rate_Reductions__
F2
Average: 8 per cent

Small customers, incl. residential: 7.5 per cent

Medium customers: 8 per cent

Large industrial customers: 11.2 per cent

The annual revenue decreases, as a result of rate reductions from the
levels in effect as of July 1, 1996, net of the monies set aside to cover
a possible settlement of the Kamine dispute, will be as follows:

July 1, 1997: $3.5 million
July 1, 1998: $9.3 million
July 1, 1999: $19.2 million
July 1, 2000: $29.0 million
July 1, 2001: $54.1 million

The rate reductions shown above will not be increased or decreased,
except as follows:
 the total cost of a resolution of Kamine issues is less than the $32.9
million RG&E has set aside, in which case the PSC can further lower
the rates by the difference;
 the benefits of debt securitization can be used to further lower the
rates;
 adjustments for SBC costs, whether or not specifically identified by
a special charge;
 competition implementation costs that exceed $2.5 million in a single
year;
 mandates and catastrophic events that individually exceed $2.5 million
may be deferred and recovered after the settlement period;
 50 per cent of any property tax variation shall be deferred until the
end of the settlement period;
 if the total of deferrals, pre-tax, either owed customers or to shareholders,
exceed $30 million; and
 annual rate changes due to the $30 million deferral limit cannot exceed
$7 million in any of the final three years.

Subject to certain contingencies, the RG&E Settlement calls for
an approximately $101 million reduction in RG&E's revenues over the
Settlement Term. RG&E will design rates that allocate the revenue reductions
evenly among service classifications except as follows: (a) monthly customer
charges to residential and small business customers will be subject to
an annual $1.50 increase, until it reaches $17.50/month; (b) the differences
between peak and shoulder-peak energy charges for large industrial customers
will be eliminated; (c) the energy audit requirement in flex-rate tariffs
will be modified; and (d) beginning on July 1, 1999 through June 30, 2002,
the rates for certain incremental manufacturing load of at least 50 KW
will be an average rate of $0.045 per KWH.

If RG&E achieves a return on common equity which exceeds 11.8 per
cent, as adjusted for any return in a prior period over the maximum, for
the Settlement Term, the excess will be treated as follows: (a) 50 per
cent will be used to write down deferrals accumulated during the Settlement
Term and RG&E can keep any remaining amount as retained earnings; and
(b) the remaining 50 per cent will be used to write down deferrals and
Sunk Costs (as defined in Subpart 7 below) and the PSC will determine the
disposition of any remaining amounts.

Back-out rates

The back-out rates for the various stages of the retail access program
are (a) approximately $0.019 per KWH in the Energy-Only Stage, and (b)
approximately $0.032 per KWH in the Energy and Capacity Stage. The $0.032
per KWH is generally expected to be equal to the incremental costs (e.g.,
O&M and capital additions) that RG&E incurs to produce power from
its fossil and hydro generating units and purchased power.

Generation Divestiture/Market Power Issues

RG&E must file a market power mitigation plan with FERC in connection
with the New York Power Pool's FERC filing for approval to form new wholesale
market institutions (i.e., an ISO, Power Exchange and New York State Reliability
Council). The PSC will implement market power mitigation measures, as appropriate,
for retail service.

RG&E is not required to divest its generation assets. However, in
the event divestiture occurs, gains from the sales will be shared by shareholders
and rate payers. If RG&E's existing generation assets are sold during
the Settlement Term, gains from the sale will be shared between shareholders
and rate payers as follow: (a) with sales occurring in the first three
years of the Settlement Term, rate payers will be entitled to 60 per cent
of the first $20 million of any gains and 80 per cent of the gains above
$20 million while RG&E will be entitled to the remaining 40 per cent
and 20 per cent respectively; and (b) with sales occurring in the last
two years of the Settlement Term, rate payers are entitled to 80 per cent
of the gains and RG&E can retain the remainder.

Corporate Restructuring

RG&E will functionally or structurally separate its existing operations
into the following: (a) a separate distribution unit ("DISCO");
(b) a separate generating unit ("GENCO"); (c) a regulated load
serving entity ("RLSE"); and (d) an unregulated load serving
entity ("ULSE"). The settlement provides that RG&E may petition
to form a holding company ("HOLDCO") as the corporate parent
for RG&E's regulated and unregulated activities resulting from the
corporate reorganization, and that the parties to the settlement will support
the petition. The DISCO will continue RG&E's transmission and distribution
services and it will own either directly, or indirectly by owning the GENCO,
RG&E's generation facilities. GENCO will operate the generation facilities
and be responsible for fixed and variable costs of the hydro and fossil
fuel units and purchased power contracts. The RLSE will provide bundled
service under tariffs to customers who elect to continue to receive it
and will be the "provider of last resort" unless the PSC approves
an alternative means of providing such service. The ULSE will be an energy
marketer and energy service provider within and outside RG&E's service
territory. Whether RG&E conducts its unregulated activities through
a HOLDCO or a separate subsidiary of a utility parent, it will be permitted
to initially fund such activities in the amount of $100 million.

The PSC will have access to the books and records of the HOLDCO and
its affiliates, subject to claims of confidentiality and privilege.

Competitive Conduct Standards and Affiliate Transactions

The RG&E Settlement contains standards of conduct which apply to
affiliate transactions between RG&E's DISCO and any of its energy supply
and energy service affiliates. These standards include the following: (a)
the DISCO cannot promote the services of its affiliates over non-affiliates
to customers in the DISCO's service territory; (b) the DISCO cannot give
preferential treatment to either its affiliates' customers or to its affiliates;
(c) if the DISCO releases customer or market information, it must be made
available to affiliates and non-affiliates on a simultaneous and comparable
basis; (d) the DISCO and any unregulated affiliate providing services in
the DISCO's service territory must conduct their businesses with separate
employees in separate buildings by July 1, 1998; and (e) asset transfers
and the purchase and sale of goods among affiliates are subject to certain
cost guidelines. The PSC may impose remedial action on the DISCO for violations
of the standards of conduct if, after giving the DISCO full and fair opportunity
to be heard, the PSC finds that violations occurred and the DISCO does
not remedy the violations within a reasonable time.

Stranded Cost Recovery

All prudently incurred costs for electric plant investments and regulatory
assets as of March 1, 1997 ("Sunk Costs"), will be recovered
by RG&E through its distribution access tariff rates through the Settlement
Term. The parties to the settlement will discuss the recovery of stranded
costs after the expiration of the Settlement Term, provided that RG&E
will have a reasonable opportunity to recover such costs following July
1, 2002. RG&E will also be permitted to recover the fixed costs of
its fossil and hydro generating units, gas turbines and power purchase
agreements (other than for Kamine) through its distribution access tariff
rates until July 1, 1999.

RG&E may recover through its retail rates all prudently incurred
cost for its nuclear generation assets (i.e., Ginna Station and RG&E's
share of Nine Mile Point No. 2 plant) provided that RG&E participates
in negotiations with the Commission staff and the other cotenants of Nine
Mile Point No. 2 plant regarding future rate treatment.

RG&E will also recover all prudently incurred incremental costs
pertaining to the shut-down and decommissioning of generating facilities
through its distribution access tariff rates. The decommissioning costs
for nuclear assets are included in the Settlement and RG&E cannot make
modifications to such costs unless approved by the PSC.

Supplier of Last Resort and Energy Service Company (ESCO) Responsibilities

As part of RG&E's corporate reorganization (described in Subpart
5 above), RG&E will form a RLSE. The RLSE will be the "provider
of last resort" unless the PSC approves an alternative means of providing
such service. The settlement sets out a general outline of the responsibilities
of load serving entities or ESCOs; however, their detailed responsibilities
will be as set out in an operating agreement under RG&E's distribution
tariff.
RG&E's Retail Access Program is a "single-retailer" model
(i.e., the customer will receive only one bill), in which RG&E will
supply distribution service to LSEs, including the RLSE, who will be directly
responsible for the distribution charges. The RLSE and other LSEs can include
distribution charges as a component of the price they bill to retail customers.

Social/Environmental Programs

(a) RG&E is allowed to petition to defer site remediation costs
that exceed, net of insurance recoveries, $2 million, annually.
(b) Low-income assistance: RG&E will continue to implement a Low-income
Program which will permit up to 1,000 customers, who meet certain criteria
to receive a 25 per cent discount on their bills and forgiveness of up
to 50 per cent of arrears after three years of satisfactory participation.
(c) Economic Development is addressed in the RG&E Settlement in terms
of the $0.045 per KWH rate for incremental manufacturing discussed above
in the Rate Design section, and in the continuation of the flex rate tariffs.

System Benefits Charge

Costs of certain mandated programs will be recovered through rates applicable
to all customers which can be through a SBC. Such mandated programs include:
research and development programs; energy efficiency programs; new, existing
or expanded low income energy efficiency programs; and, environmental protection
programs. It is estimated that funding for these programs, over three years,
will be $14.7 million. RG&E is not required to contribute to the SBC
program administered by NYSERDA.

Reliability Incentives/Penalties

RG&E will continue a Service Quality Performance Program ("SQP
Program") through June 30, 1999. RG&E will pay penalties to customers,
up to $1.25 million in the aggregate, for failure to achieve minimum criteria
established in the RG&E Settlement for service quality.

Nuclear Generation Issues

All prudently incurred costs of RG&E's nuclear power plant ownership
interests will be recovered through retail rates. RG&E, however, shall
participate in 'good-faith' negotiations with the DPS Staff and the co-tenants
of Nine Mile Point No. 2 plant regarding future rate treatment of such
facility. Similarly, there are to be discussions concerning the Ginna Plant.
The discussions should lead to a statewide solution, not an RG&E-specific
agreement. These plants are subject to a provision that in the event of
one or more "mandates" or "catastrophic events," when
the costs exceed $2.5 million, RG&E may defer such costs and recover
them subsequently through rates.

Long Island Lighting Company/The Brooklyn Union Gas Company

On February 5, 1998, the PSC issued an order in Case 97-M-0567 adopting
terms of a settlement agreement ("LILCO/Brooklyn Union Settlement")
by which the PSC authorized LILCO and Brooklyn Union to proceed with a
corporate combination. The bases for the decision are set forth in PSC
Opinion No. 989. The combination is expected to occur by means of a share
exchange between the companies and a holding company. Brooklyn Union had
previously, on September 29, 1997, completed a reorganization by which
it became a wholly-owned subsidiary of a holding company, which restructuring
had been authorized by the PSC in Opinion No. 96-26.
On June 26, 1997 LILCO entered into an agreement with LIPA which contemplates
the acquisition by LIPA of LILCO's electric transmission and distribution
system, its interest in the Nine Mile Point No. 2 plant and the electric
regulatory assets which are now owned by LILCO. LILCO's gas assets and
operations, the non-nuclear generating assets and operations would be transferred
to LILCO subsidiaries whose stock would be owned by the new holding company
associated with the corporate combination.

One or more of the holding company's subsidiaries would then provide certain
management services to LIPA with respect to the operation and maintenance
of the electric transmission and distribution system, provide electric
capacity and energy to LIPA from the generating plants and provide energy
management services to purchase fuel and electric capacity and manage the
scheduling and sale of electric capacity and energy for LIPA.

LILCO's electric operations restructuring requirements and timetables differ
somewhat from other New York State electric companies. Those provisions
noted below are, in the most part, derived from the LILCO/Brooklyn Union
Settlement and summarize provisions (on which the PSC has acted) which
apply to the LILCO electric operations. Brooklyn Union does not have electric
utility operations.

Rate Plan

LILCO/Brooklyn Union's rate plan

The electric rate plan under the LILCO/Brooklyn Union Settlement provides
credits which would reduce the non-fuel components of LILCO's base rates
by an average 3.21 per cent and fuel charges by an average 0.63 per cent.
This rate plan would have a total bill impact of an average rate reduction
of 2.47 per cent commencing on the consummation of the merger.

LILCO has extended suspension dates in Case 96-E-0132, a rate filing, until
at least July 1, 1998. On or about May 1, 1998, all parties to Case 97-M-0567
and Case 96-E-0132 will be invited to confer regarding LILCO's electric
rates in light of the facts and circumstances at that time.

LIPA's rate plan

On April 9, 1998, LIPA announced a decision of its Trustees ("Decision")
to implement rate reductions for Long Island customers, to become effective
following LIPA's acquisition of LILCO as described above. While the LIPA
rate plan replaces the LILCO rate plan discussed above, LIPA will continue
LILCO's current rate designs. LIPA's new rates, as announced on April 9,
1998, would represent an average rate reduction of 20 per cent. This reduction
includes the reduction identified by LILCO/Brooklyn Union, discussed above.

Retail Access Schedule

LIPA has proposed, subject to the approval of its Trustees, a three-phase
retail access program. Beginning on January 1, 1999, a pilot group of customers
with an aggregate demand of 100 MW, evenly divided between residential
and business customers, will be solicited. Deliveries from alternate suppliers
will commence by May 1999. Phase II will involve an increase of the customer
load for which retail access will be available by 400 MW, as well as the
number of customers which will again be split evenly between residential
and business. In Phase III of the program, customer choice will be increased
so that by January 1, 2003, all remaining LIPA customers will be able to
participate. LIPA has proposed that participants in all phases will be
eligible to purchase both capacity and energy needs from suppliers of their
choice.

Rate Design and Back-Out Rates

In the event that the transaction with LIPA identified at the outset
of this Subpart is consummated, it is expected the LIPA will promulgate
new rates consistent with the overall rate reduction detailed in its Decision
and identified in Subpart 1.b, above. The LIPA rate plan announced in the
Decision has the following key elements:

Residential rates

The LIPA rates will continue LILCO's rate design which includes use
of a "declining block" design for winter months and an "increasing
block" design for summer months. Mandatory time of use rates will
be discontinued for large users.

Non-residential rates

Commercial customers will continue to pay a seasonally-adjusted rated;
commercial customers with demand in excess of 500 KW in the winter (or
145 KW in the summer) will continue to have mandatory time of use provisions.

Buy-back rates

LIPA will continue to have buy-back rates under a tariff based on time
differentiation and LIPA's avoided costs. Energy and capacity payments
will continue in accordance with LILCO's existing contractual arrangements.

Shoreham property tax settlement

LIPA proposed in its Decision to accept $625 million in settlement of
the claims against Suffolk County, the Town of Brookhaven and several special
service districts (school, fire and library) for excessive property taxes
assessed on LILCO, and excessive payments in lieu of taxes imposed on LIPA,
in connection with their ownership of Shoreham. This sum would be returned
to Long Island rate payers in the form of one-time rebate checks and credits
on customers' electric bills for five years. LIPA plans to implement the
rate aspects of its expected settlement of the Shoreham property tax dispute
(1) as a part of LIPA's commencement of service under new electric rates
and (2) prior to concluding a final settlement of the property tax dispute.
The impact on LIPA's rates of the expected Shoreham property tax settlement
are included in LIPA's rate plan described above.

Generation Divestiture/Market Power Issues

LILCO's non-Long Island generation, namely its interest in the Nine
Mile Point No. 2 plant, is proposed to be transferred to LIPA. In addition,
LILCO will transfer its electric transmission and distribution system to
LIPA. The new holding company, through one or more LILCO subsidiaries,
as noted above, will operate the transmission and distribution system for
LIPA.

Corporate Restructuring

The proposed corporate combination between Brooklyn Union and LILCO
is to be accomplished by a share exchange and the creation of a holding
company. In addition, the proposed LIPA transaction identified above is
expected to occur shortly before the Brooklyn Union  LILCO combination.

Competitive Conduct Standards and Affiliate Transactions

The LILCO/Brooklyn Union Settlement provides specific guidance on many
activities among the new holding company, utility subsidiaries, non-utility
subsidiaries and affiliates. It also provides competitive conduct standards.

Allocation of common costs and accounting for transactions between and
among the new holding company and its subsidiaries

One or more corporate services subsidiaries will be formed, as subsidiaries
to the new holding company, to perform the functions common to both utility
operations and the unregulated subsidiaries of the new holding company.
Distribution of costs will be based on causality with no requirement to
capture incidental labor time.
(i) Transactions Between the New Holding Company and its Subsidiaries
The following procedures set forth the manner in which holding company
costs, whether benefiting a subsidiary or of a general corporate nature,
are to be charged to the subsidiaries.
 Direct charges are related to authorized services provided by the holding
company or to the holding company by an affiliate. These services are charged
to the benefiting entity on a direct time and materials basis. Affiliate
business areas providing services to the holding company will report direct
labor through the payroll system and other charges as appropriate.
 Allocated charges have been developed to distribute to affiliates costs
that are not directly charged. Except for payroll loadings, which will
be allocated to the subsidiaries based on direct or indirect labor charges,
all other holding company costs which are not directly charged will be
allocated to affiliates and business units within affiliates using a formula
based on the ratio of the sum of revenues, net plant and direct payroll
expense to the consolidated (holding company) total of these items. Building
services costs charged to the holding company and allocated to the affiliates
using the above formula will be determined based on the percentage of the
total square footage of the corporate headquarters occupied by the holding
company.
(ii) Transactions Between the Corporate Services Subsidiary(s) and the
Affiliates of the New Holding Company
The following procedures set forth the manner in which all costs associated
with work performed by the corporate services subsidiary(s) for affiliates
or business units within affiliates is to be charged to the respective
affiliates or business units within affiliates.
 Direct charges are related to authorized services provided by the corporate
services subsidiary(s) to other subsidiaries of the holding company and
vice versa. These services are charged to the benefiting entity on a direct
time and materials basis. Labor costs will include an allocation for payroll
loadings. Business areas will report direct labor through the payroll system
and other charges as appropriate. Incidental labor charges should not be
reported.
 Allocated charges will be used to distribute to affiliates costs that
are not directly charged, based on an average cost per activity.
The remaining expenses of the corporate services subsidiary(s) represent
costs associated with performing general corporate functions. These costs
will be allocated to affiliates and business units within affiliates using
a formula based on the ratio of the sum of revenues, net plant and direct
payroll expense to the consolidated (holding company) total of these items.

Provision of services
(i) Service companies may provide corporate administrative services to
regulated companies with protections provided for customer information
and system information.
(ii) Utility service companies may provide certain services to the jurisdictional
subsidiaries.
(iii) Regulated subsidiaries may engage in tariffed and non-tariffed transactions
with each other but there are prohibitions against jurisdictional subsidiaries
providing marketing services, transmission and distribution system planning,
and use of marketing employees; any provision of goods or services between
regulated subsidiaries and non-utility subsidiaries calls for written contracts
and filings with the PSC.

Other restrictions on affiliate transactions

(i) Non-utility subsidiaries may not be located in the same building
as regulated subsidiaries but the new holding company and service companies
may be so located.
(ii) Limitations and restrictions on asset and employee transfers between
the regulated subsidiaries, the service companies and the new holding company
will be established.
(iii) Prior PSC approval is required for any loans, guarantees or credit
support by the regulated utilities to the new holding company or non-utility-subsidiaries.
(iv) Standards of conduct between a regulated subsidiary and an energy
related business affiliate include requirements both for compliance with
generic conditions of the Electric Competitive Opportunities Proceeding
(Case 94-E-0952):
 Requirements for safeguards to protect regulated subsidiary customer
information and system information from access or use by any ESCO affiliates;
 Requirements to provide customers of regulated subsidiaries with lists
of all qualified ESCOs;
 Offer of regulated electric service to similarly situated non-affiliated
suppliers and customers in the service territory at the same prices, terms
and conditions of service offered to affiliates or their customers and
requirement that individually negotiated arrangements with affiliates or
their customers be posted expeditiously on an electronic bulletin board;
and
 Where regulated service offerings are limited and affiliates or their
customers would qualify, those services shall be offered on an open season
basis.

Stranded Cost Recovery

There is no explicit CTC included in LILCO's rates. The transfer of
LILCO's interest in the Nine Mile Point No. 2 plant and LILCO's regulatory
assets to LIPA is intended, however, to allow for stranded cost recovery.

Supplier of Last Resort and Energy Service (ESCO) Responsibilities

Under the LILCO-LIPA transaction and under LIPA's retail access proposal,
LIPA will be the supplier of last resort of electric service in what is
currently the LILCO service territory.

Social/Environmental Programs

LILCO has no low-income electric rate or assistance program. Some of
the environmental programs are subject to consummation of the combination
between LILCO and Brooklyn Union and last until November 30, 2000, and
some may be terminated if the LILCO transmission and distribution systems
are transferred to another entity. The requirements would require LILCO
to:
(a)Create a multi-disciplinary renewable energy committee;
(b)Establish a fuel cell and photovoltaic demonstration program;
(c)Continue demand side management and research and development programs;
(d)Continue working with PSC on distribution pricing structure;
(e)Continue participation in Ozone Transport Assessment Group and join
Ozone Attainment Coalition;
(f)Review major transmission and distribution projects to determine whether
there are cost-effective alternatives with consideration to minimizing
environmental impacts;
(g)Participate in market transformation collaboratives; and
(h)Support adoption of improved building codes and standards.

System Benefits Charge
LIPA has committed to create a $32 million (2 mills per KWH) Clean Energy
Fund in the first year of its operation of the system to support energy
efficiency and renewables on Long Island. LIPA will appoint an advisory
panel for the Fund to recommend a permanent funding mechanism to continue
support for the Fund at the $32 million per year level.

Reliability Incentives/Penalties

LILCO has committed in Case 97-M-0567 to reliability incentives and
penalties commencing December 1, 1997 and in effect for each twelve month
period thereafter until modified or discontinued by the PSC, or the consummation
of the LIPA transaction. Those service quality measurement criteria are
set forth in the table below.

F_FREQUENCY_OF_OUTAGES
TARGETS
Average Interruption Frequency in each of LILCO's four Divisions: Western
and Eastern Suffolk, Central and Queens-Nassau for Each Year (Excluding
Major Storms)
Minimum level set for each division in Case 90-E-1119:
Western Suffolk - 1.60 Hours
Eastern Suffolk - 2.10 Hours
Central - 1.40 Hours
Queens-Nassau - 1.23 Hours

DURATION_OF_OUTAGES
TARGETS
Customer Average Interruption Duration in each of LILCO's four Divisions:
Western and Eastern Suffolk, Central and Queens-Nassau for Each Year (Excluding
Major Storms)
Minimum level set for each division in Case 90-E-1119:
Western Suffolk - 1.21 Hours
Eastern Suffolk - 1.19 Hours
Central - 1.35 Hours
Queens-Nassau - 1.12 Hours

Nuclear Generation Issues

LILCO's interest in the Nine Mile Point No. 2 plant is proposed to be
transferred to LIPA. LIPA will use the output reflected by this share to
assist in meeting the needs of electric customers on Long Island.

Mergers and Acquisitions

Investments by the new holding company in non-utility businesses are
limited generally to 50 per cent of total new holding company capital and
must be made in areas described below unless otherwise approved by the
PSC.

Energy-related business

Businesses that engage, as lessee, operator or owner, in the ownership,
manufacture, production, transmission, distribution, storage and/or brokering
and/or marketing of, or exploration for or production or gathering of:
gas (natural or synthetic), electricity or steam or other energy sources;
fuels for light, heat, transportation or power; devices for and equipment
used in connection with the production of energy or fuel; appliances and
equipment that consume or utilize gas (natural or synthetic) or electricity
or steam or other energy sources; devices used in the control of, and information
relating to the use of, natural or synthetic gas, electricity or steam
or other energy sources; and businesses that provide services related to
such activities, including without limitation management, project management,
engineering and construction services.

Water, environmental and technical services

Businesses that include water distribution; waste management; pollution
control systems; laboratory testing services; waste management services;
management and consulting businesses related to such activities; and businesses
that provide services related to these endeavors.

Telecommunication business

Businesses that include voice, video or data transmission services by
radio, telephone, telegraph, fiber optics, cable or other means of communication,
providing general or specialized information and databases, and radio,
television or cable broadcasting, and designing engineering, manufacturing,
constructing, maintaining, selling or leasing facilities and equipment
for any such activities.

Area development business

Businesses that operate primarily in Brooklyn Union's service area and
that contribute to the economy of such service area by providing significant
employment, the construction and/or improvement of the housing stock and/or
commercial and industrial facilities and otherwise generally contribute
to the overall economic health and well-being of Brooklyn Union's service
territory.

The seven utility restructuring plans discussed above in Part II are
intended to produce reduced electricity prices for all New York State customers
over the long-term and, in most cases, in the short-term as well. The magnitude,
timing and source of savings will vary from utility to utility, and among
different customer classes. In general, there are three distinct sources
of expected savings. The scheduled rate reductions identified in Part II
have been agreed to by the respective utility companies and approved by
the PSC. These scheduled rate reductions are the most certain to occur.
The two other sources of savings, discussed below, may result in further
savings for customers.
Additional, competition-stimulated price reductions for consumers which
elect to take service from a competitive ESCO are a second source of potential
savings. These expected savings result from the commencement of a competitive
market in which customers may shop for energy from competing suppliers.
The prices charged by companies offering electricity in competition with
the regulated utility are expected to be below the regulated utilities'
approved rate schedules as these companies compete on price, as well as
on other terms and conditions of service. The dimensions of the savings
resulting from this source are hard to project.

A third source of savings may result from the divestiture of certain electric
generating assets. Five of the six New York electric utilities which have
detailed restructuring plans have announced plans to divest a significant
part of their non-nuclear generation capacity. If the results of these
asset sales are comparable to the (thus far) limited experience with sales
of generating plants in other states, the selling utilities can look forward
to receiving a premium over book value from the buyers for their divested
assets. Most of the restructuring plans allocate a significant portion
of any such premium to the reduction of the companies' stranded investments
and costs. Thus, there is a potential for the level of stranded investments,
which the utilities are authorized to recover through the CTC, to be reduced
as a result of the utilities' gains on the divestiture of their generation
assets. However, to the extent that gains on divestiture sales are not
sufficient to offset stranded costs, the CTC may exert significant upward
pressure on electricity prices actually experienced by customers, particularly
in the intermediate-to-long term.

How Will the Benefits and Burdens of Competition Be Shared?

Residential customers

The scheduled rate reductions for residential customers specified above
in Part II are not as large on a percentage basis as for industrial customers.
A potential issue in the restructuring of New York's electric utility industry
is whether the magnitude of these reductions is so low as to make the introduction
of the restructured market appear unimportant to residential customers,
who are also voters. At this point it is not possible to state with assurance
whether the public yet senses that any beneficial change will be made in
electric bills.

Commercial and industrial customers

Commercial and industrial customers have generally received larger percentage
scheduled rate reductions in the restructuring plans. Moreover, these customers
stand to gain more from a competitive energy market, because energy and
capacity constitute a far larger portion of their total electric bill.
These customers, for whom the cost of electricity is often a critical component
of the cost of production, have demonstrated sophistication in electric
rate matters and have participated effectively in the restructuring proceedings.
Commercial and industrial customers are, of course, of particular concern
to the State's regulators and policy makers as they are both the source
of jobs and, relative to residential customers, significantly more mobile.
Industrial customers, for example, can relocate their facilities to other
states, or other parts of the globe. Nevertheless, the rate reductions
contemplated in the utility restructurings discussed in Part II do not
necessarily bring New York's electric rates for these customers down to
the national average. Will the price reductions contemplated in the restructurings
provide a sufficient stimulus to these customers that they remain in business
in New York and, even better, expand their businesses?

Utility, IPP and ESCO investors

While some of the restructuring plans put the utilities "at risk"
for a portion of their potentially stranded investments, the amounts at
risk do not appear to threaten their financial stability. Indeed, in some
respects the plans may leave the utility investors better off. The risk
of bankruptcy for Niagara Mohawk, for example, is significantly reduced
as a result of the adoption of its restructuring plan, known as PowerChoice.
Looking to the future, it is likely that the nature of the utility business
will change as a result of restructuring, with consequences that are not
entirely predictable. Two hypothetical examples illustrate this potential
change in business orientation. A utility company might choose to remain
basically 'pipes and wires'-oriented, that is, to focus on its transmission
and distribution businesses. Such a company will be exposed to fewer marketplace
risks, and, under continued rate regulation, may not be allowed to earn
rates of return on invested equity capital that are as high in real terms
as today's allowed rates of return. Another company, in pursuit of higher
profits, might emphasize more its unregulated business activities and,
thus, increase its risk profile, at least as compared to the hypothetical
'pipes and wires' company. This diversification strategy recalls the experience
of utilities in the 1980s when many companies entered new lines of business
divorced from the electric utility business and thus outside of the utilities'
traditional area of expertise. Many of those investments did not fare well.
The threat of the past few years to the enforceability of power purchase
agreements ("PPAs") between IPPs and utilities, upon which IPP
investors and lenders have relied, seems to be greatly diminished or eliminated
as a result of the restructuring settlements. The decision by the PSC to
provide a reasonable opportunity for utilities to recover above market
payments made under PPAs, coupled with lower prices for electricity, reduced
the pressure on utilities to continue to seek to terminate PPAs prematurely.
Thus, there is increased likelihood that IPP investors will recover all
or the bulk of their investment. Again focusing on Niagara Mohawk as an
example, the resolution of the economic burden of its PPAs was a key issue
in the company's restructuring. After years of efforts to amend or terminate
these contracts, Niagara Mohawk entered into the MRA with 16 IPPs with
which it had 29 PPAs and thereby reduced Niagara Mohawk's above-market
costs. At the same time, the MRA provided the settling IPPs with assurance
of recovery of a reasonable share of the benefits for which the IPPs had
contracted in their PPAs.

On the other hand, IPPs will be increasingly exposed to market forces.
IPPs that were able to secure long-term, regulatorily-approved PPAs in
the old business environment will now have to build new plants and operate
existing plants as 'merchant' generators. Companies will increasingly have
to rely on short-term market performance, in place of firm, long-term contracts.

ESCO managers and their investors may also find the newly competitive market
even more difficult, as they encounter increasingly intense competition.
Retail marketers must compete in the near term with the incumbent utility
as well as other marketers, some of whom operate nationally and in many
different fields (e.g., fuels, commodities and wholesale power).

State and local government (tax revenues and tax base)

State and local governments may feel the most immediate financial effects
of utility restructuring if increased economic activity attributable to
lower electricity prices does not generate sufficient tax revenue to offset
lower tax collections associated with lower electricity prices. Local assessments
of property used for generation plants have often exceeded those for other
industrial property. The owners of competitive generating facilities will
likely seek to reduce the assessments, and as the utilities divest their
plants, the methods used to make these assessments seem likely to change.
On the other hand, to the extent that sales of plants in other states may
be at prices in excess of book value, it is possible that some assessments
could increase.

State taxes, such as the gross receipts tax imposed on utility receipts,
seem likely to decline as well. New York has already enacted phased reductions
in the gross receipts tax. This year, at least one proposal is before the
Legislature to accelerate the pace of these reductions of gross receipts
taxes. Sales tax revenues too may change. Under current law, if transmission
and delivery services are purchased as an unbundled service, they are not
subject to sales tax. These potential changes in the level of taxes imposed
on the retail customer appear likely to be a major contributor to customers'
savings in the near-term.

The Customer Experience under Competition

New products and services

Economists suggest competition not only produces lower consumer prices,
but also better and more varied goods and services. Whether residential
electric customers will view the restructuring of their utility as providing
better and more varied services is a question that cannot be answered at
this time, although service innovations are certainly possible in a number
of areas, such as unified billing for customers who receive service at
multiple locations and 'one stop shopping,' in which electricity, gas,
telecommunications and internet access are provided by a single supplier.
Also, restructuring will provide an instant benefit to customers who highly
value freedom of choice.

New technology has already played a significant role in the electric utility
industry, as improved combined cycle, gas-fueled power plants have driven
down the cost of power from new plants. Larger, more efficient combined
cycle plants may prove to be even more cost effective At the same time,
some industry analysts foresee a bright future for distributed generation,
as more affordable fuel cells and micro turbines become more easily achievable.
The siting and transmission issues associated with central station generation,
such as plants in the 500-1500 MW range, differ markedly from the issues
associated with plants that are one-tenth or one-hundredth the size. Highly
efficient, small generators would give customers new self- and co-generation
options and reduce the need for high voltage transmission lines.

Reliability

Reliability is usually considered the unarguable, fundamental requirement
for successful operation of the U.S. electrical system. Reliability issues,
however, almost always have an economic aspect and the resolution of reliability
issues will play an important role in the economics of restructuring the
utility industry. Under traditional regulation, the reliability of the
transmission system is maintained through the voluntary cooperation of
the regulated utilities. As competitive pressures spread, will reliance
on voluntary organizations continue to be an effective means of ensuring
system integrity? As competition becomes more important, decisions will
be made about which body, for example, will establish the standards for,
and limits on, system operations. Who will participate in the formulation
and refinement of reliability rules? Who will plan and execute the new
construction needed to maintain system reliability? Who will provide the
capital for new facilities needed for the continued development of the
market, but of limited profitability to individual market participants?
The answers to these questions have not yet been resolved.

Environmental issues

The advent of retail competition in New York brings both opportunities
and risks for the environment. On the positive side, technological improvements
in energy generation have already resulted in new, more efficient power
plants that produce only a fraction of the emissions of older, less efficient
plants. As discussed above, there is a potential for further development
of distributed generation using a variety of environmentally compatible
technology. Displacement of older plants with newer, cleaner generators
will improve air quality and reduce greenhouse emissions. The emphasis
on efficiency of operation resulting from competition is likely to lead
to environmental benefits. Retail competition also offers customers the
opportunity to vote with their pocketbooks and choose 'green' electricity
sources as opposed to other energy sources which are lower priced, but
not as environmentally compatible.

Restructuring of the electric industry, however, may pose a number of potential
hazards for the environment. An increased emphasis on short-term price
considerations may result in increased generation from coal-burning power
plants. Another concern is that competition will disadvantage and undercut
energy efficiency as an alternative to electricity generation. Funding
for energy conservation and energy efficiency has already been reduced
by more than two-thirds from 19921994 levels.

Economic and Political Effects at State and Local Levels

A major goal of electric restructuring is to reduce energy prices in
order to increase economic activity in the state. Two questions that will
require continuing attention over the transition period contemplated in
the restructuring plans are whether the level of rate reductions contemplated
in New York's restructuring plans is sufficient to increase economic activity
and whether any increase in economic activity can be measured and correlated
to the reduction in power costs. Restructuring will also affect tax collections,
though, as noted above, increased economic activity may offset reduced
tax collections due to lower electricity prices and competitive pricing.

Utility Restructuring Programs

Organizational Restructuring

Six of the seven New York utility companies have announced plans to
restructure their companies as a part of the PSC-approved restructuring
plans. (LILCO also is expected to restructure its operations as a result
of its combination with Brooklyn Union and its transaction with LIPA.)
In general, each company is permitted to form a holding company with a
subsidiary that continues the regulated transmission and distribution business
of the utility (the "T&D Company") and at least one unregulated
affiliate. The restructuring plans of four of the utilities provide for
an unregulated affiliate to act as a marketing company. The PSC has allowed
these marketing affiliates to sell to retail customers in the service territory
of the T&D Company.

The nature and control over the relations between the T&D Company and
the holding company's other affiliates are important aspects of the restructuring
plans. As discussed above in Part II, each of the seven plans contains
provisions addressing affiliate transactions and competitive conduct standards.

An area of potential disputes will be in the exchange of property between
the T&D Company and an affiliate. What valuation should be placed on
such property? Is it sufficient to allow transfers of property at its book
value, when the market value significantly exceeds the book value? In New
York, the PSC has traditionally required (in the sense of imputing the
revenue to the regulated company) the transfer to be at the higher of market
price or book value.

Complaints arising from such disputes may be lodged with the PSC. While
the PSC has considered the potential for such complaints in at least one
of the restructuring opinions, how such complaints will be addressed by
the PSC remains to be worked out.

Litigation

Several litigation challenges to the industry restructuring described
in this report are pending. In particular, these claims raise the issue
of the legal authority of the PSC to undertake the restructuring. The pending
claims are identified here.
(a)In Public Utility Law Project v. Public Service Commission, Index No.
4509-96, Decision and Order (Sup. Ct., Albany County Apr. 29, 1997), (petitioners'
claim that residential service provided by gas marketers is subject to
the Home Energy Fair Practices Act ("HEFPA"), Article 2 of the
Public Service Law was dismissed by Supreme Court) (appeal pending);
(b)In Energy Association of New York v. Public Service Commission, 169
Misc. 2d 924 (Sup. Ct., Albany County 1996), (Supreme Court rejected the
utilities' challenge, inter alia, to the legal authority of the PSC to
oversee the restructuring of the electric utility industry). While an appeal
is pending, this case, as noted above, is subject to a conditional withdrawal
by the utilities;
(c)In Public Utility Law Project v. Public Service Commission, Index No.
5685-97 (Sup. Ct., Albany County, filed Sept. 15, 1997), petitioners challenge
the PSC's ESCO order (Opinion No. 97  5) claiming, inter alia, that ESCOs
are subject to HEFPA; and
(d)In Public Utility Law Project v. Public Service Commission, Index No.
894-98 (Sup. Ct., Albany County) and Travelers Group, Inc. v. Public Service
Commission, Index No. 1155-98 (Sup. Ct., Albany County), petitioners contest
the PSC's order approved the Con Edison restructuring plan.

Merger Activity

The potential for merger activity in the electric utility industry is
influenced by a number of factors, several of which discourage mergers
or combinations. First, PUHCA requires the parent company of two or more
utilities using the holding company form of organization, that are not
in adjoining states or otherwise exempted from the Act's requirements,
to register as a holding company. Such registration exposes the utilities
to substantial regulatory burdens. Second, the fact that utilities are
regulated at both the state and federal level, and thus need regulatory
approval of both state and federal authorities to merge, exposes any electric
utility merger to extensive regulatory review. Third, it appears from the
mergers that have been proposed in other states that regulators may require
that all, or at least a significant portion, of any premium paid for the
target company be paid by the shareholders, not the rate payers. Thus,
a merger may have an adverse impact on earnings of the merged company at
least initially.
At the same time, it is reasonable to assume that most utilities are considering
the possibility of merger opportunities. The size of a company may be a
factor in its success in a competitive market and the emergence of utilities
from the regulated world into a competitive world requires that they consider
this issue. Larger utilities can adopt different strategies than smaller
ones. Larger utilities, for example, can hedge business risks in one geographic
market by operating in several markets at the same time. Investments in
service operations are very large, and may require a large customer base
to be feasible.

In New York, as noted above in Part II, one intra-state combination between
contiguous utilities is nearing a closing, namely the merger of Brooklyn
Union and LILCO. On May 11, 1998, Con Edison announced an agreement under
which, subject to regulatory and O&R shareholder approvals, Con Edison's
parent company will acquire for cash all of O&R's common stock. In
addition, in 1997, a tender offer was made by CalEnergy Company, Inc. for
9.9 per cent of the common shares of a second utility, NYSEG. CalEnergy
also proposed to NYSEG to negotiate an acquisition of all of NYSEG's shares.
This offer and proposal were eventually withdrawn by CalEnergy.

Diversification

In the 1980's, electric utilities across the United States undertook
active diversification programs. These companies invested in businesses
related to the utility business and, in some cases, in businesses with
no connection to the utility industry. While some of these ventures were
successful, many of the investments in unrelated businesses were not successful.
In a few cases, these unrelated investments were spectacularly unsuccessful.
New York utilities generally avoided the most egregious of the diversification
pitfalls that many other U.S. utilities experienced. As New York utilities
face the competitive market, a major strategic question for each company
will be whether to diversify their operations.

Generation Divestiture

As noted above, five of the utility companies in New York have committed
to divestiture of all or a significant portion of their fossil-fueled (and,
in some cases, hydro) generation. While the buyers may be large utilities
or their affiliates with operations within or without New York, it is also
possible that "non-utility" companies will buy some of these
plants.

A significant issue is who will benefit from any premium over book value
the utilities may receive for their divested assets. The most well known
cases to date, outside New York, of divestiture of assets by utilities
as a part of industry restructuring involve payment by buyers of premiums
over book value. While these may merely be examples of the benefits of
being the 'first mover,' this experience is influencing New York regulators
and utility executives to expect that premiums will be paid. As discussed
above in Part II, any such premium will be shared between the shareholders
and customers.

Finally, another important issue is how utilities receiving significant
cash proceeds through divestiture auctions will use these funds. Utilities
electing to pursue a "wires-only" model are likely to have cash
substantially in excess of the needs of their transmission and distribution
operations. This "surplus" cash may drive utilities in one (or
more) of three directions: diversification; acquisition of another utility;
or a common stock buy-back. One New York utility, Con Edison, has announced
both an acquisition and a common stock buy-back.

Transmission System Issues

The Independent System Operator

The ISO, when approved by FERC, will replace the transmission-related
operational responsibility of the seven New York electric utilities, NYPA
and the New York Power Pool. Although ownership of transmission facilities
will be unchanged, the ISO will be responsible for the operation of the
transmission grid in a safe and reliable manner and for the administration
of a statewide transmission tariff. The ISO will also be responsible for
generation dispatch based, in part, on input from one or more power exchanges.
The ISO will conduct an auction, or settlement, twice for each hour's production
(a "two settlement" approach): first, there is a "day ahead"
market with firm commitments made, and, second, there will be a "real
time" market. Other power exchanges can also be established to schedule
transactions for market participants and have the information delivered
to the ISO.

A decision by FERC on the ISO proposal is expected by mid-1998.

Transmission System Planning

Transmission system planning is also proposed to be performed by the
ISO, as a result of an amendment to the ISO proposal filed by the New York
utilities in December, 1997. ISO transmission planning is intended to relieve
congestion "bottleneck problems."

What is not resolved, however, is the means of payment for transmission
system upgrades. In the competitive market, it is less clear who benefits
and who is responsible for upgrades in transmission capacity. This issue
is before FERC in its review of the December 1997 filing.

Securitization

Securitization is a financing device which may reduce the costs of the
transition to a competitive electric market. Securitization legislation
proposed in New York would enable the PSC to issue irrevocable and assignable
rate orders authorizing the collection of a non-bypassable charge designed
to recover stranded costs resulting from the transition to competition.
These orders would be pledged to a financing entity as collateral for,
and in exchange for the proceeds of, bonds issued by the entity to refinance,
at a lower cost, the utility securities originally issued to carry the
stranded costs. The necessary legislation has been introduced, but as of
May 1998, it had not been enacted. Similar legislation is in effect in
other states, and utilities have "securitized" portions of their
stranded costs and regulatory assets.

Statement of Financial Accounting Standards No. 71

Only regulated enterprises whose operations meet the criteria of Statement
of Financial Accounting Standards No. 71 ("SFAS No. 71"), "Accounting
for the Effects of Certain Types of Regulation," may account for their
operations in accordance with SFAS No. 71, which in certain instances provides
for accounting treatment for regulated enterprises that differs significantly
from that applied to non-regulated enterprises. Under an accounting standard
applicable to restructuring utilities, SFAS No. 101, a utility that is
no longer regulated, and thus no longer has assurance of recovering its
costs, is treated like other non-regulated companies. In particular, assets
for which there is no assurance of recovery of capital must be written-off
without deferral. If only some of an enterprise's operations are regulated
and meet the criteria of SFAS No. 71, that standard is applied only to
the regulated portion of the enterprise's operations.

Will the switch from accounting under SFAS No. 71 make a difference? In
the case of Con Edison, the company announced in its 1997 Third Quarter
financial statements that the application of SFAS No. 101 had no material
adverse effect on Con Edison's financial position or results of operations.
The note to Con Edison's financial statements explains that the estimated
cash flows from the operation and/or sale of the fossil generating assets
together with the cash flows from the strandable cost recovery provisions
of the Con Edison Settlement Agreement will not be less than the net carrying
costs of its assets; that recovery of the approximately $275 million of
net regulatory assets attributable to the deregulated portion of the business
is probable under the Con Edison Settlement Agreement; and that Con Edison
has not accrued a loss for its IPP contracts because it is not probable
that the charges by the IPPs will exceed the sum of the cash flows from
the sale of the electricity provided by the IPPs and the cash flows provided
pursuant to the Con Edison Settlement Agreement.

CONCLUSION

This Report summarizes the historic restructuring of the electric utility
industry in New York, including developments in May 1998. Restructuring
is not complete, however, and developments continue and will continue for
a number of years.

This utility industry restructuring undertaking by the PSC is one of the
most far-reaching regulatory undertakings in New York State history. The
stakes of the restructuring are enormous, given the size of the investment
of society in electric facility infrastructure, the pervasiveness of electricity
in every day life, and the role of electricity prices in the economy. This
restructuring effort thus merits the continuing attention of all who would
understand and participate in New York's future.